____________
|
(1) |
Includes a seven firm year transportation agreement for 80,000 MMBtus/d with an estimated starting date in October 2009. |
Off Balance Sheet Arrangements
We currently do not have any off balance sheet arrangements.
Financing Arrangements
Senior Secured Revolving Credit Facility
On May 25, 2006, we entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent. The Senior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially
all of our proved oil & gas assets and is guaranteed by our subsidiaries CCBM, Inc., CCLR, Inc., Carrizo (Marcellus) LLC and Carrizo Marcellus Holding Inc.
In the fourth quarter of 2008, we amended the Senior Credit Facility to (1) increase the borrowing base to $250.0 million; (2) extend the maturity date to October 29, 2012; (3) increase the maximum total net debt to Consolidated EBITDAX to 4.0 to 1.0; (4) change the semi-annual borrowing base redetermination dates to March 31 and September
30; (5) change the interest rate provisions; and (6) replace JPMorgan Chase with Guaranty Bank as the administrative agent bank.
If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the
lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.
The annual interest rate on each base rate borrowing is (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 0.75% and 2.25% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the
adjusted Daily LIBO rate on such day plus a margin between 2.0% to 3.5% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan is the adjusted daily LIBO rate plus a margin between 2.0% to 3.5% (depending on the then-current level of borrowing base usage). At February 17, 2009, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.4%.
We are subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.0 to 1.0; and (2) a maximum total net debt to
Consolidated EBITDAX (as defined in the Senior Credit Facility) of 4.0 to 1.0. Although we currently believe that we can comply with all of our financial covenants with the business plan that we have put in place, our business plan is based on a number of assumptions, the most important of which is a relatively stable, natural gas
price at economically sustainable levels. If the price that we receive for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants in our Senior Credit Facility, including the financial covenants discussed above. In order to provide a further margin of comfort with regards to these financial covenants, we may seek to further reduce our capital and exploration budget,
sell non-strategic assets, opportunistically modify or increase our natural gas hedges or approach the lenders under our Senior Credit Facility for modifications of either or both of the financial covenants discussed above. There can be no assurance that we will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our Senior Credit Facility if a precipitous decline in natural gas prices were to occur in the future. The Senior Credit Facility
also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.
The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.
At December 31, 2008, we were in compliance with all of our debt covenants.
As of March 2, 2009, we had $179.0 million of borrowings outstanding and a borrowing base availability of $71.0 million.
Convertible Senior Notes
In May 2008, we issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process, into a combination of cash and our
common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of our conversion obligation in excess of such principal amount. The notes are convertible into our common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain
fundamental changes occur on or before June 1, 2013, we will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported
sale price of our common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of our
common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028. The holders of the Convertible Senior Notes may require us to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to
100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. We may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.
The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility, the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.
The Convertible Senior Notes are unsecured obligations and rank equal to all future senior unsecured debt but rank second in priority to the Senior Credit Facility.
As prescribed by APB 14-1, on the date of issuance we valued the Convertible Senior Notes as $309.6 million of debt and $64.2 million of equity, representing the fair value of the conversion premium. The resulting debt discount will be amortized to interest expense through June 1, 2013,
the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, resulting in an effective interest rate of approximately 8% for the Convertible Senior Notes.
Second Lien Credit Facility
On July 21, 2005, we entered into a Second Lien Credit Agreement with Credit Suisse, as administrative agent and collateral agent and the lenders party thereto (the “Second Lien Credit Facility”). The Second Lien Credit Facility, as amended, provided for a term loan facility in an aggregate principal amount of $225.0 million.
In May 2008, we repaid in full the $219.9 million outstanding under the Second Lien Credit Facility and terminated the facility in connection with the issuance of the Convertible Senior Notes.
Public Offerings in 2008 and 2007; and Private Placement of Common Stock in 2006.
In February 2008, we sold 2,587,500 shares of our common stock in an underwritten public offering at a price of $54.50 per share, raising $135.1 million of net proceeds. With a portion of the proceeds we repaid $85.0 million of borrowings then outstanding under the Senior Credit Facility. We used the remaining proceeds to fund in part
our 2008 capital expenditure program.
In September 2007, we sold 1,800,000 shares of our common stock to certain qualified investors in a registered direct offering at a price of $41.40 per share, raising $72.0 million of net proceeds. We used the net proceeds to repay $54 million of outstanding borrowings under the Senior Credit Facility and to fund in part our 2007 capital
expenditure program.
In July 2006, we sold 1,350,000 shares of our common stock to institutional investors at a price of $26.00 per share in a private placement (the “2006 Private Placement”). The net proceeds, after deducting placement agents’ fees but before paying offering expenses, of approximately $33.7 million were principally used
to fund a portion of our 2006 capital expenditures program. In connection with the 2006 Private Placement, we entered into Subscription and Registration Rights Agreements (the “Subscription and Registration Rights Agreements”) with the investors in the 2006 Private Placement. The Subscription and Registration Rights Agreements provide registration rights with respect to the shares purchased in the 2006 Private Placement. We filed a resale shelf registration statement in connection with the 2006 Private
Placement that has been declared effective by the Commission. We are generally subject to specified penalties in the event we do not maintain the effectiveness of the registration statement. We are subject to certain covenants under the terms of the Subscription and Registration Rights Agreements, including the requirement that the registration statement be kept effective for resale of shares for two years. In certain situations, we are required to indemnify the investors in the 2006 Private Placement, including
without limitation, for certain liabilities under the Securities Act.
Lease Option Arrangements
Due to the limited capital available at times to fund all of our ongoing lease acquisition efforts in the Barnett Shale, Marcellus Shale, Fayetteville Shale and other plays, we elect from time to time to enter into various lease purchase option agreements with a number of third parties, including, in 2006, Steven A. Webster, who is the
Chairman of our Board of Directors. The lease purchase option arrangement with Mr. Webster expired at the end of 2006. The terms and conditions of the lease purchase option arrangement with Mr. Webster were consistent with the lease purchase option arrangements we entered into with unrelated third parties. These lease purchase option arrangements provide us the option to purchase leases from the counterparties, over an option period, generally 90 days, for the counterparties’ original cost of the leases
plus an option fee. We paid Mr. Webster fees totaling approximately $250,000 in 2006. In accordance with the lease purchase option agreement, we also assigned to him an overriding royalty interest on any lease we acquired from Mr. Webster under the lease purchase option agreement with him, which overriding royalty interest varied from one-half to one percent of 8/8ths, proportionally reduced to the actual net interest in any given lease acquired from Mr. Webster. We paid Mr. Webster approximately $430 and $50
in 2008 and 2007, respectively, for overriding royalties under these arrangements.
In order to expand our lease acquisition efforts in the Marcellus Shale play, the Company elected to enter into a lease option agreement effective August 1, 2008 with Avista, our partner in the Marcellus Shale play. See “Business and Properties—Significant Project Areas; Marcellus Shale Area.” The terms and conditions
of the lease purchase option arrangement with Avista were generally consistent with lease option arrangements that we have traditionally entered into with other third parties. Avista paid approximately $27.5 million for the oil and gas leases under the lease purchase option agreement and subsequently contributed these properties at their cost to our Marcellus joint venture, effective August 1, 2008.
We have continued to enter into lease purchase option arrangements with third parties from time to time. We currently have one lease purchase option arrangement with an unrelated third party. Strategically, these leasing arrangements have allowed us to temporarily control important acreage positions during periods that we have lacked sufficient
capital to directly acquire such oil and gas leases. We may continue to use these arrangements as a strategic alternative in the future.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing natural gas and oil prices. The dramatic drop in natural gas and oil prices in 2008 has resulted in a significant drop in revenue per unit of production. Although operating costs have come down slightly in recent months, the rate of decline in natural gas and oil prices
has been substantially greater. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent months, inflation could become a significant issue in the future.
Recently Issued Accounting Pronouncements
In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring transparency about
the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We do not believe the adoption of SFAS No.
161 will have a significant effect on our consolidated financial position, results of operations or cash flows.
On December 31, 2008, the Securities and Exchange Commission (SEC) adopted major revision to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors.
The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that the present value of oil and gas reserves be reported and to be used in the full-cost ceiling test calculation be based upon an average price
for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.
Recently Adopted Accounting Pronouncements
We adopted the Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS No. 157”), effective January 1, 2008. SFAS No. 157 provides a framework for measuring fair value and
enhances related disclosures. The implementation of SFAS No. 157 did not change our current valuation method and did not have a material effect on our consolidated financial position or results of operations. We included additional disclosures in the Notes to Consolidated Financial Statements with respect to the measurement of our assets and liabilities at fair value on the balance sheet date.
We adopted FSP APB 14-1 effective January 1, 2009. This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt
and Debt Issued with Stock Purchase Warrants.” Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP requires retrospective application. We valued the 4.375% Senior Convertible Notes due 2028 as $309.6 million
of debt and $64.2 million of equity, representing the fair value of the conversion premium on the date of issuance, and recognized an additional $1.8 million in interest expense (net of $4.9 million of capitalized interest) during 2008, resulting in an effective interest rate of approximately 8% for 2008.
We adopted EITF 03-6-1 effective January 1, 2009. This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. We
determined that our shares of restricted stock qualified as participating securities and included these shares in both the basic and diluted earnings per share for all periods presented.
Summary of Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 2 to our consolidated financial statements.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Actual results could differ from these estimates. The use of these estimates significantly affects our natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair
value of derivatives, stock-based compensation expense, contingencies and the results of future and current litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimate. Accordingly,
reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of our common stock and corresponding volatility and our ability to generate future taxable
income. Future changes to these assumptions may affect these significant estimates materially in the near term.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally
consolidate our interests in natural gas and oil properties. We capitalized compensation costs and other costs for employees working directly on exploration activities of $7.8 million, $4.5 million and $3.5 million in 2008, 2007 and 2006, respectively. We expense maintenance and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. Costs not subject to amortization include costs of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and exploratory wells in progress. These costs are periodically
evaluated, on a property-by-property basis, for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for 2008, 2007 and 2006 was $2.23, $2.36 and $2.61, respectively.
We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.
The net capitalized costs of proved oil and natural gas properties are limited to a “ceiling test” based on the estimated future net revenues, discounted at a 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions (the “Full Cost Ceiling”). If net capitalized costs
exceed this limit, the excess is charged to earnings.
The Full Cost Ceiling impairment at the end of 2008 of approximately $178.5 million was based upon average realized oil, natural gas liquids and natural gas prices of $40.12 per Bbl, $19.62 per Bbl and $4.99 per Mcf, respectively, or a volume weighted average price of $29.86 per BOE. We would not have had a Full Cost Ceiling write-down
at an estimated volume weighted average price of $35.25 per BOE. The Full Cost Ceiling impairment was primarily the result of the decline in commodity prices. The prices used in the ceiling test impairment were the prices in effect at December 31, 2008, as contemplated by current Commission rules that require the use of prices in effect on the last day of the relevant financial period. These rules are expected to change in the future to require the use of an average price over a twelve-month period.
Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of our oil and natural gas properties (excluding unevaluated
costs) and estimated future development costs less net
salvage value to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.
We have a significant amount of proved undeveloped reserves. We had 239.1 Bcfe, 185.8 Bcfe and 126.2 Bcfe of proved undeveloped reserves, representing 48%, 53% and 60% of our total proved reserves at December 31, 2008, 2007 and 2006, respectively. As of December 31, 2008, less than 13% of these proved undeveloped reserves, or approximately,
29.9 Bcfe, were attributable to our Camp Hill properties that we acquired in 1994. See “Business and Properties Significant Project Areas — Camp Hill Area” for further discussion of the Camp Hill properties. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties.
Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion
rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of non-depleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall
depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our net income by, (1) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (2) an estimated $5.9 million in 2003 (due to higher depletion expense), (3) an estimated $3.4 million in 2004 (due
to higher depletion expense), (4) an estimated $6.9 million in 2005 (due to higher depletion expense), (5) an estimated $0.7 million in 2006 (due to higher depletion expense), (6) an estimated $2.0 million in 2007 (due to higher depletion expenses) and (7) an estimated $9.2 million in 2008 (comprised of after-tax charges for a $8.5 million full cost ceiling impairment and a $0.7 million depletion expense increase).
We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration.
If our level of total proved reserves, finding cost and current prices were all to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The proved reserve data as of December 31, 2008 included in this document are estimates prepared by Ryder Scott Company, LaRoche Petroleum Consultants, Ltd., and Fairchild & Wells, Inc., Independent Petroleum Engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be
measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The Commission mandates some of these assumptions such as oil and natural gas prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending
on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with Commission requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate, using a discount rate of 10%.
Our rate of recording depreciation, depletion and amortization expense for proved properties is dependent on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. A 10% increase or
decrease in our proved reserves would have increased or decreased our depletion expense by nine percent for the year ended December 31, 2008.
As of December 31, 2008, approximately 58% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2008 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric
analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause
the discontinuation of the classification of these reserves as proved. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field’s development. The average life of the Camp Hill proved undeveloped reserves is approximately 15 years,
with 50% of these reserves being booked over ten years ago. Although we have increased the pace of the development of the Camp Hill project, there can be no assurance that the aforementioned discontinuance will not occur.
Derivative Instruments
We use derivatives, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and gas production. We also used derivatives to manage the variable interest rate on the Second Lien Credit Facility prior to its termination in May 2008. We have elected to account for our derivative contracts as non-designated
derivatives that will be marked-to-market. For a discussion of the impact of changes in the prices of oil and gas on our hedging transactions, see “Volatility of Oil and Natural Gas Prices” below.
Our Board of Directors sets all of our risk management policies and reviews volume limitations, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief
Financial Officer and Chairman of the Board. The master contracts with the approved counterparties identify the President and Chief Financial Officer as the only representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities quarterly.
Upon entering into a derivative contract, we either designate the derivative instrument as a hedge of the variability of cash flow to be received (cash flow hedge) or the derivative must be accounted for as a non-designated derivative. All of our derivative instruments at December 31, 2008, 2007 and 2006 were treated as non-designated
derivatives and the unrealized gains related to the mark-to-market valuation was included in our earnings.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities
and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt
to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. See
“Item 1A. Risk Factors—Natural gas and oil prices are highly volatile, and have declined significantly since mid-2008, and lower prices will negatively affect our financial condition planned, capital expenditures and results of operations.”
We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Commission. See “—Summary of Critical Accounting Policies—Oil and Natural Gas Properties” and “Item 1A. Risk Factors— We may record ceiling limitation write-downs that would reduce
our shareholders’ equity.”
To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection. We do not hold or issue derivative instruments for trading purposes.
The following table includes oil and natural gas derivative positions settled during the years ended December 31, 2008, 2007 and 2006 and the unrealized gain (loss) associated with the outstanding oil and natural gas derivatives at December 31, 2008, 2007 and 2006.
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Oil positions settled (Bbls) |
|
|
64,100 |
|
|
|
52,000 |
|
|
|
82,200 |
|
|
Natural gas positions settled (MMBtu) |
|
|
15,733,000 |
|
|
|
7,846,000 |
|
|
|
5,481,000 |
|
|
Realized gain ($ millions) (1) |
|
$ |
0.6 |
|
|
$ |
5.8 |
|
|
$ |
6.8 |
|
|
Unrealized gain (loss) ($ millions) (1) |
|
$ |
38.6 |
|
|
$ |
(4.6 |
) |
|
$ |
8.7 |
|
____________
|
(1) |
Included in gain (loss) on derivatives, net in the Consolidated Statements of Operations. |
At December 31, 2008, approximately 69% of our open natural gas hedges were with Credit Suisse and the remaining 31% were with Shell Energy North America (US), L.P. The open oil hedges were with Credit Suisse.
While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivative transactions with two counterparties and have a netting agreement in place with those counterparties. We do
not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would again be exposed to price risk. We have additional risk of financial loss because the
price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our derivative arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.
Our natural gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the Houston Ship Channel or WAHA index for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the West
Texas Intermediate index for each trading day of a particular calendar month.
At December 31, 2008 we had the following open derivative positions:
| |
|
Natural Gas Swaps |
|
|
Natural Gas Collars |
|
|
Basis Differential Swaps(2) |
|
| |
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed |
|
|
|
|
|
Floor |
|
|
Ceiling |
|
|
|
|
|
|
|
|
Quarter |
|
MMbtu |
|
|
Price(1) |
|
|
MMBtu |
|
|
Price(1) |
|
|
Price(1) |
|
|
MMBtu |
|
|
Price |
|
|
First Quarter 2009 |
|
|
2,803,000 |
|
|
$ |
6.13 |
|
|
|
2,520,000 |
|
|
$ |
7.37 |
|
|
$ |
9.10 |
|
|
|
310,000 |
|
|
$ |
0.31 |
|
|
Second Quarter 2009 |
|
|
1,547,000 |
|
|
|
5.40 |
|
|
|
2,548,000 |
|
|
|
7.12 |
|
|
|
8.85 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2009 |
|
|
- |
|
|
|
- |
|
|
|
2,576,000 |
|
|
|
7.16 |
|
|
|
8.88 |
|
|
|
920,000 |
|
|
|
0.31 |
|
|
Fourth Quarter 2009 |
|
|
- |
|
|
|
- |
|
|
|
2,576,000 |
|
|
|
7.17 |
|
|
|
8.90 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,620,000 |
|
|
|
7.92 |
|
|
|
9.63 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,638,000 |
|
|
|
7.18 |
|
|
|
8.89 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,656,000 |
|
|
|
7.35 |
|
|
|
9.06 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,656,000 |
|
|
|
7.45 |
|
|
|
9.16 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
450,000 |
|
|
|
9.70 |
|
|
|
11.70 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
8.25 |
|
|
|
10.25 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
460,000 |
|
|
|
8.65 |
|
|
|
10.65 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
460,000 |
|
|
|
8.85 |
|
|
|
10.85 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2012 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
9.55 |
|
|
|
11.55 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2012 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
8.35 |
|
|
|
10.35 |
|
|
|
- |
|
|
|
- |
|
|
TOTAL |
|
|
4,350,000 |
|
|
|
|
|
|
|
19,525,000 |
|
|
|
|
|
|
|
|
|
|
|
1,230,000 |
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil Collars |
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
Quarter |
|
Bbls |
|
|
Floor Price(3) |
|
|
Ceiling Price(3) |
|
|
First Quarter 2009 |
|
|
9,000 |
|
|
$ |
131.65 |
|
|
$ |
151.65 |
|
|
Second Quarter 2009 |
|
|
9,100 |
|
|
|
131.40 |
|
|
|
151.40 |
|
|
Third Quarter 2009 |
|
|
9,200 |
|
|
|
130.85 |
|
|
|
150.85 |
|
|
Fourth Quarter 2009 |
|
|
9,200 |
|
|
|
130.35 |
|
|
|
150.35 |
|
|
TOTAL |
|
|
36,500 |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Based on Houston Ship Channel and WAHA spot prices. |
|
(2) |
Basis differential swaps cover the price differential for natural gas between NYMEX and HSC. |
|
(3) |
Based on West Texas intermediate index prices. |
In the first quarter of 2009, in order to monetize some profitable hedge positions, we sold down a portion of our oil hedge positions, receiving $2.2 million in proceeds. We also converted a 2010 natural gas costless collar position into a 2009 natural gas fixed price swap to further mitigate the risk of declining natural gas prices in
2009. As of March 2, 2009, we had the following open derivative positions:
| |
|
Natural Gas Swaps |
|
|
Natural Gas Collars |
|
|
Basis Differential Swaps(2) |
|
| |
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed |
|
|
|
|
|
Floor |
|
|
Ceiling |
|
|
|
|
|
|
|
|
Quarter |
|
MMbtu |
|
|
Price(1) |
|
|
MMBtu |
|
|
Price(1) |
|
|
Price(1) |
|
|
MMBtu |
|
|
Price |
|
|
First Quarter 2009 |
|
|
2,803,000 |
|
|
$ |
6.13 |
|
|
|
2,520,000 |
|
|
$ |
7.37 |
|
|
$ |
9.10 |
|
|
|
- |
|
|
$ |
- |
|
|
Second Quarter 2009 |
|
|
5,187,000 |
|
|
|
5.34 |
|
|
|
2,548,000 |
|
|
|
7.12 |
|
|
|
8.85 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2009 |
|
|
3,680,000 |
|
|
|
5.31 |
|
|
|
2,576,000 |
|
|
|
7.16 |
|
|
|
8.88 |
|
|
|
920,000 |
|
|
|
0.31 |
|
|
Fourth Quarter 2009 |
|
|
3,680,000 |
|
|
|
5.58 |
|
|
|
2,576,000 |
|
|
|
7.17 |
|
|
|
8.90 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2010 |
|
|
1,800,000 |
|
|
|
5.57 |
|
|
|
1,620,000 |
|
|
|
7.92 |
|
|
|
9.63 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2010 |
|
|
1,820,000 |
|
|
|
5.57 |
|
|
|
182,000 |
|
|
|
7.35 |
|
|
|
9.15 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2010 |
|
|
1,840,000 |
|
|
|
5.57 |
|
|
|
184,000 |
|
|
|
7.35 |
|
|
|
9.15 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2010 |
|
|
1,840,000 |
|
|
|
5.57 |
|
|
|
184,000 |
|
|
|
7.35 |
|
|
|
9.15 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2011 |
|
|
1,800,000 |
|
|
|
5.64 |
|
|
|
450,000 |
|
|
|
9.70 |
|
|
|
11.70 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2011 |
|
|
1,820,000 |
|
|
|
5.64 |
|
|
|
455,000 |
|
|
|
8.25 |
|
|
|
10.25 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2011 |
|
|
1,840,000 |
|
|
|
5.64 |
|
|
|
460,000 |
|
|
|
8.65 |
|
|
|
10.65 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2011 |
|
|
1,840,000 |
|
|
|
5.64 |
|
|
|
460,000 |
|
|
|
8.85 |
|
|
|
10.85 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2012 |
|
|
910,000 |
|
|
|
5.88 |
|
|
|
455,000 |
|
|
|
9.55 |
|
|
|
11.55 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2012 |
|
|
910,000 |
|
|
|
5.88 |
|
|
|
455,000 |
|
|
|
8.35 |
|
|
|
10.35 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2012 |
|
|
920,000 |
|
|
|
5.88 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2012 |
|
|
920,000 |
|
|
|
5.88 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
TOTAL |
|
|
33,610,000 |
|
|
|
|
|
|
|
15,125,000 |
|
|
|
|
|
|
|
|
|
|
|
920,000 |
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Based on Houston Ship Channel and WAHA spot prices. |
|
(2) |
Basis differential swaps cover the price differential for natural gas between NYMEX and HSC. |
Item 8. Financial Statements and Supplementary Data
The response to this item is included elsewhere in this report.
Item 9A. Controls and Procedures (Restated)
(a) Disclosure Controls and Procedures. We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to
the Securities and Exchange Commission (the “Commission”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In accordance with Exchange Act Rules 13a-15(b) and 15d-15(b), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined by Exchange Act Rules 13a-15(e) and 15d-15(e)
as of the end of the period covered by this report. As described below under paragraph (b) within Management's Annual Report on Internal Control over Financial Reporting, we identified a material weakness in our internal control over financial reporting. As a result of this material weakness, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K/A, our disclosure controls and procedures were not effective to provide
reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Commission under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate
to allow timely decisions regarding required disclosure. We have outlined a number of initiatives designed to address this material weakness, as discussed below under paragraph (b) of this Item 9A. In addition, we were required to seek relief under Rule 12b-25 in connection with the filing of our Annual Report on Form 10-K
for the year ended December 31, 2008 (“2008 Form 10-K”) to obtain additional time to complete the financial statements and secondary reviews needed to finalize the 2008 Form 10-K due to an impairment to oil and gas properties resulting from a decline in prices for natural gas and oil.
The audit report of Pannell Kerr Forster of Texas, P.C., which is included in this 2008 Form 10-K/A, expressed an unqualified opinion on our consolidated financial statements.
(b) Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, as amended. Our
internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
|
· |
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; |
|
· |
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and |
|
· |
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. |
While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud
caused by collusion of two or more people, including our senior management. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this evaluation, management used the Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of our evaluation, our management concluded that our internal control over financial reporting was not effective as of December 31, 2008 for the reason identified below.
Subsequent to the issuance of the 2008 Form 10-K, we identified an error resulting from the presence of certain computational deficiencies in our standard ceiling test computation format, most notably the absence of the pre-tax, gross-up computation and a reconciling proof of the oil and gas property and related deferred tax amounts to
the financial statements (in the event of an after-tax, ceiling test write-down). Upon further review, we also discovered additional errors which partially offset the impact of the pre-tax, gross-up error. These offsetting errors included: (1) the incorrect classification of a portion of the capitalized interest in the full cost pool that related to unevaluated properties, (2) the failure to properly consider certain deferred tax amounts and (3) the incorrect classification of certain unevaluated
costs in the full cost pool.
These errors and/or omissions resulted in a restatement of the 2008 consolidated financial statements and were an indication that a material weakness was present at December 31, 2008, increasing the likelihood to more than remote that a material misstatement of our annual or interim financial statements would not be prevented or detected. These
deficiencies ultimately affect the accuracy of our financial statement reporting and disclosures. As a result, management has concluded that our internal controls over financial reporting were not effective as of December 31, 2008. We have outlined certain procedures, discussed below, that are designed to prevent these specific errors from occurring in the future.
We have taken or plan to take the following initiatives in the third quarter of 2009: (1) delegate preparation of certain critical workpapers to our financial reporting staff allowing our financial reporting manager to perform more qualitative review analysis, (2) remove the computational deficiencies from our standard ceiling test workpaper
format, (3) improve workpaper formats and implement comparative analysis within these critical workpapers to enhance qualitative analysis and (4) prepare a reconciliation of the
quarter-to-quarter changes in costs associated with unevaluated property and proved undeveloped locations that will be used to determine the reclassification of costs to the full cost pool.
We have discussed this material weakness and our planned remediation steps with our Audit Committee and believe that such enhanced procedures and workpaper formats, once fully implemented, will prospectively mitigate this material weakness.
Pannell Kerr Forster of Texas, P.C., our former independent registered public accounting firm that audited our consolidated financial statements, has also issued its own report on the effectiveness of our internal control over financial reporting as of December 31, 2008, which is filed herewith.
(c) Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting. As described above in paragraph (b) of this Item 9A under Management's Annual Report on Internal Control over Financial Reporting, we identified a material weakness in our internal control over financial reporting and have described a number of planned changes to our internal control over financial reporting that are expected to be fully implemented by the end of the third quarter 2009 and once fully implemented, should remediate
this weakness.
PART IV
(a)(1) Financial Statements
The response to this item is submitted in a separate section of this report.
(a)(3) Exhibits
EXHIBIT INDEX
|
Exhibit Number |
|
|
|
Description |
|
†2.1 |
|
– |
|
Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of September 6, 1997 (incorporated herein by reference to Exhibit 2.1 to
the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). |
|
†3.1 |
|
– |
|
Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998). |
|
†3.2 |
|
– |
|
Articles of Amendment to Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008). |
|
†3.3 |
|
– |
|
Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on January 3, 2008). |
|
†4.1 |
|
– |
|
Indenture among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee, dated May 28, 2008 (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 28, 2008). |
|
†4.2 |
|
– |
|
First Supplemental Indenture dated May 28, 2008 between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 28, 2008). |
|
†10.1 |
|
– |
|
Amendment No. 1 to the Letter Agreement Regarding Participation in the Company’s 2001 Seismic and Acreage Program, dated June 1, 2001 (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). |
|
*†10.2 |
|
– |
|
Amended and Restated Incentive Plan of the Company effective as of February 17, 2000 (incorporated herein by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000). |
|
*†10.3 |
|
– |
|
Amendment No. 1 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002). |
|
*†10.4 |
|
– |
|
Amendment No. 2 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002). |
|
*†10.5 |
|
– |
|
Amendment No. 3 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Appendix A to the Company’s Proxy Statement dated April 21, 2003). |
|
*†10.6 |
|
– |
|
Amendment No. 4 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Appendix B to the Company’s Proxy Statement dated April 26, 2004). |
|
*†10.7 |
|
– |
|
Amendment No. 5 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 16, 2005). |
|
*†10.8 |
|
– |
|
Amendment No. 6 to the Amended and Restated Incentive Plan of the Company (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 19, 2005). |
|
*†10.9 |
|
– |
|
Amendment No.7 to the Amended and Restated Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on May 30, 2006). |
|
*†10.10 |
|
– |
|
Employment Agreement between the Company and S.P. Johnson IV (incorporated herein by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). |
|
*†10.11 |
|
– |
|
Employment Agreement between the Company and J. Bradley Fisher (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-2 (Registration No. 333-111475)). |
|
*†10.12 |
|
– |
|
Employment Agreement between the Company and Paul F. Boling (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-2 (Registration No. 333-111475)). |
|
*†10.13 |
|
– |
|
Employment Agreement between the Company and Gregory E. Evans dated March 21, 2005 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 22, 2005). |
|
*†10.14 |
|
– |
|
Employment Agreement between Carrizo Oil & Gas, Inc. and Richard Smith dated September 18, 2006, and effective as of August 23, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 22, 2006). |
|
*†10.15 |
|
– |
|
Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998). |
|
*†10.16 |
|
– |
|
Form of Amendment to Executive Officer Employment Agreement (incorporated herein by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K dated January 8, 1998). |
|
*†10.17 |
|
– |
|
Form of Amendment to Executive Officer Employment Agreement (incorporated herein by reference to Exhibit 99.7 to the Company’s Current Report on Form 8-K dated December 15, 1999). |
|
*†10.18 |
|
– |
|
Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to Exhibit 99.8 to the Company’s Current Report on Form 8-K dated December 15, 1999). |
|
*†10.19 |
|
– |
|
Form of Amendment to Executive Officer Employment Agreement (incorporated herein by reference to Exhibit 99.7 to the Company’s Current Report on Form 8-K dated February 20, 2002). |
|
*†10.20 |
|
– |
|
Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to Exhibit 99.8 to the Company’s Current Report on Form 8-K dated February 20, 2002). |
|
*†10.21 |
|
– |
|
Amendment to the Employment Agreement between the Company and S.P. Johnson IV (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 27, 2006). |
|
*†10.22 |
|
– |
|
Amendment to the Employment Agreement between the Company and Paul F. Boling (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 27, 2006). |
|
*†10.23 |
|
– |
|
Amendment to the Employment Agreement between the Company and Gregory E. Evans (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8- K filed on January 27, 2006). |
|
*†10.24 |
|
– |
|
Amendment to the Employment Agreement between the Company and J. Bradley Fisher (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on January 27, 2006). |
|
*†10.25 |
|
– |
|
Amendment to the Employment Agreement between Carrizo Oil & Gas, Inc. and S.P. Johnson IV effective December 19, 2008 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
*†10.26 |
|
– |
|
Amendment to the Employment Agreement between Carrizo Oil & Gas, Inc. and Paul F. Boling effective December 19, 2008 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
*†10.27 |
|
– |
|
Amendment to the Employment Agreement between Carrizo Oil & Gas, Inc. and J. Bradley Fisher effective December 19, 2008 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
*†10.28 |
|
– |
|
Amendment to the Employment Agreement between Carrizo Oil & Gas, Inc. and Gregory E. Evans effective December 19, 2008 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
*†10.29 |
|
– |
|
Amendment to the Employment Agreement between Carrizo Oil & Gas, Inc. and Richard H. Smith effective December 19, 2008 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
*†10.30 |
|
– |
|
Form of Stock Option Award Agreement (incorporated herein by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004). |
|
*†10.31 |
|
– |
|
Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 19, 2005). |
|
*†10.32 |
|
– |
|
Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 19, 2005). |
|
*†10.33 |
|
– |
|
Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 19, 2005). |
|
*†10.34 |
|
– |
|
Form of Employee Restricted Stock Award under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on January 27, 2006). |
|
*†10.35 |
|
– |
|
Form of Employee Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). |
|
*†10.36 |
|
– |
|
Form of Employee Stock Option Award Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). |
|
*†10.37 |
|
– |
|
Form of Independent Contractor Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on May 30, 2006). |
|
*†10.38 |
|
– |
|
Form of Employee Restricted Stock Award Agreement (with performance-based vesting) (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on December 23, 2008). |
|
†10.39 |
|
– |
|
S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). |
|
†10.40 |
|
– |
|
S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). |
|
†10.41 |
|
– |
|
Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (incorporated herein by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K dated December 15, 1999). |
|
†10.42 |
|
– |
|
Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (incorporated herein by reference to Exhibit 99.5 to the Company's Current Report on Form 8-K dated February 20, 2002). |
|
†10.43 |
|
– |
|
Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, National Association, as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger (incorporated herein by reference
to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 30, 2006). |
|
†10.44 |
|
– |
|
First Lien Stock Pledge and Security Agreement dated as of May 25, 2006, by Carrizo Oil & Gas, Inc., in favor of JPMorgan Chase Bank, National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on May 30, 2006). |
|
†10.45 |
|
– |
|
Second Amendment effective as of September 11, 2007 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, National Association, as Administrative Agent and Lender, and Guaranty Bank as Lender (incorporated herein by reference
to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 11, 2007). |
|
†10.46 |
|
– |
|
Third Amendment effective as of December 20, 2007 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, National Association, as Administrative Agent and Lender, and Guaranty Bank as Lender (incorporated by reference to Exhibit
10.48 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008). |
|
†10.47 |
|
– |
|
Fourth Amendment to Credit Agreement, dated as of May 20, 2008, by and among Carrizo Oil & Gas, Inc. and certain subsidiaries thereof, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 22, 2008). |
|
†10.48 |
|
– |
|
Fifth Amendment to Credit Agreement dated as of June 11, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed on July 11, 2008). |
|
†10.49 |
|
– |
|
Sixth Amendment dated as of July 7, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s
Current Report on Form 8-K filed on July 11, 2008). |
|
†10.50 |
|
– |
|
Seventh Amendment dated as of October 29, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A., as resigning administrative agent and as resigning issuing bank, and Guaranty Bank, as successor
administrative agent and as successor issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 4, 2008). |
|
†10.51 |
|
– |
|
Lender Certificate dated December 16, 2008 of Union Bank of California, N.A. regarding joinder as Lender to Credit Agreement, as amended, dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, Guaranty Bank, as Administrative Agent and the Lenders party thereto (incorporated
herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 22, 2008). |
|
*10.52 |
|
– |
|
Base Salaries for certain Executive Officers. |
|
*21.1 |
|
– |
|
Subsidiaries of the Company. |
|
**23.1 |
|
– |
|
|
|
**23.2 |
|
– |
|
|
|
**23.3 |
|
– |
|
|
|
**23.4 |
|
– |
|
|
|
**31.1 |
|
– |
|
|
|
**31.2 |
|
– |
|
|
|
**32.1 |
|
– |
|
|
|
**32.2 |
|
– |
|
|
|
*99.1 |
|
– |
|
Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2008. |
|
*99.2 |
|
– |
|
Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2008. |
|
*99.3 |
|
– |
|
Summary of Reserve Report of LaRoche Petroleum Consultants, Ltd. as of December 31, 2008. |
__________
* Previously filed
** Filed herewith.
CARRIZO OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
PAGE |
|
|
F-2 |
|
|
F-4 |
|
|
F-5 |
|
|
F-6 |
|
|
F-8 |
|
|
F-9 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Carrizo Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. as of December 31, 2008 and 2007 and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement
schedule included on page 61. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Carrizo Oil & Gas, Inc. at December 31, 2008 and 2007 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally
accepted accounting principles.
As discussed in Note 2, the Company has restated its previously issued consolidated financial statements for 2008 to correct a misstatement in the amount of their ceiling test impairment and have adjusted the 2008 financial statements for the retroactive application of APB No. 14-1, “Accounting
for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)” and have adjusted all years presented for the retroactive application of FSP Emerging Issues Task Force No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.”
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 12, 2009, except for the restatement of Management’s Annual Report on Internal Control Over Financial Reporting, for which the date is August 17, 2009, expressed an adverse opinion on the Company’s internal control over financial reporting.
/s/ Pannell Kerr Forster of Texas, P.C.
Houston, Texas
March 12, 2009
(Except for Notes 2, 4, 5, 6 and 13 for which
the date is August 17, 2009.)
REPORT OF INDEPENENT REGISTERED PUBLIC ACCOUNTING FIRMS
Board of Directors and Shareholders
Carrizo Oil & Gas, Inc.
Houston, Texas
We have audited the internal control over financial reporting of Carrizo Oil & Gas, Inc. (the “Company”) as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control
over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As stated in Management’s Annual Report on Internal Control over Financial Reporting, management’s assessment of the effectiveness of the Company’s internal control over financial reporting has been restated to reflect the impact of a material weakness in internal control over financial reporting.
In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the December 31, 2008 consolidated financial statements of the Company. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the December 31, 2008 consolidated
financial statements, and this report does not affect our report dated March 12, 2009, except for Notes 2, 4, 5, 6 and 13 for which the date is August 17, 2009, which expressed an unqualified opinion on those consolidated financial statements.
/s/ Pannell Kerr Forster of Texas, P.C.
Houston, Texas
March 12, 2009
(Except for the restatement of Management’s Annual Report on Internal
Control Over Financial Reporting, for which the date is August 17, 2009)
CARRIZO OIL & GAS, INC.
(As Restated and Adjusted (See Note 2))
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands, except per share amount) |
|
|
ASSETS |
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
5,184 |
|
|
$ |
8,026 |
|
|
Accounts receivable, trade (net of allowance for doubtful accounts of $1,264 and |
|
|
24,675 |
|
|
|
27,114 |
|
|
$1,430 at December 31, 2008 and 2007, respectively) |
|
|
|
|
|
|
|
|
|
Advances to operators |
|
|
336 |
|
|
|
1,113 |
|
|
Fair value of derivative financial instruments |
|
|
22,791 |
|
|
|
1,126 |
|
|
Prepayments and deposits |
|
|
3,335 |
|
|
|
3,913 |
|
|
Deferred tax asset |
|
|
- |
|
|
|
324 |
|
|
Total current assets |
|
|
56,321 |
|
|
|
41,616 |
|
|
PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil and natural |
|
|
|
|
|
|
|
|
|
gas properties (including costs not subject to amortization of $378,634 and |
|
|
|
|
|
|
|
|
|
$170,586 at December 31, 2008 and 2007, respectively) |
|
|
986,629 |
|
|
|
646,810 |
|
|
DEFERRED FINANCING COSTS, NET |
|
|
8,430 |
|
|
|
5,921 |
|
|
INVESTMENTS |
|
|
3,274 |
|
|
|
11,071 |
|
|
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS |
|
|
15,876 |
|
|
|
- |
|
|
OTHER ASSETS |
|
|
1,172 |
|
|
|
3,245 |
|
|
TOTAL ASSETS |
|
$ |
1,071,702 |
|
|
$ |
708,663 |
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
Accounts payable, trade |
|
$ |
46,683 |
|
|
$ |
49,700 |
|
|
Accrued liabilities |
|
|
54,149 |
|
|
|
36,091 |
|
|
Advances for joint operations |
|
|
3,815 |
|
|
|
872 |
|
|
Current maturities of long-term debt |
|
|
173 |
|
|
|
2,251 |
|
|
Fair value of derivative financial instruments |
|
|
- |
|
|
|
2,755 |
|
|
Deferred tax liability |
|
|
9,103 |
|
|
|
- |
|
|
Total current liabilities |
|
|
113,923 |
|
|
|
91,669 |
|
|
LONG-TERM DEBT, net of current maturities and debt discount |
|
|
475,788 |
|
|
|
252,250 |
|
|
ASSET RETIREMENT OBLIGATION |
|
|
6,503 |
|
|
|
5,869 |
|
|
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS |
|
|
- |
|
|
|
1,050 |
|
|
DEFERRED INCOME TAXES |
|
|
34,778 |
|
|
|
46,321 |
|
|
DEFERRED CREDITS |
|
|
625 |
|
|
|
783 |
|
|
COMMITMENTS AND CONTINGENCIES |
|
|
- |
|
|
|
- |
|
|
SHAREHOLDERS’ EQUITY: |
|
|
|
|
|
|
|
|
|
Common stock, par value $0.01 (90,000 shares authorized with 30,860 and 28,009 |
|
|
|
|
|
|
|
|
|
issued and outstanding at December 31, 2008 and 2007, respectively) |
|
|
309 |
|
|
|
280 |
|
|
Additional paid in capital |
|
|
420,778 |
|
|
|
239,672 |
|
|
Retained earnings |
|
|
20,297 |
|
|
|
65,344 |
|
|
Accumulated other comprehensive income (loss), net of tax |
|
|
(1,299 |
) |
|
|
5,425 |
|
|
Total shareholders’ equity |
|
|
440,085 |
|
|
|
310,721 |
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
$ |
1,071,702 |
|
|
$ |
708,663 |
|
| |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(As Restated and Adjusted (See Note 2))
| |
|
For the Years Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands, except per share amounts) |
|
|
OIL AND NATURAL GAS REVENUES |
|
$ |
216,677 |
|
|
$ |
125,789 |
|
|
$ |
82,945 |
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas operating expenses (exclusive of depletion, |
|
|
37,885 |
|
|
|
24,662 |
|
|
|
16,428 |
|
|
depreciation and amortization, shown separately below) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Third party gas purchases |
|
|
6,570 |
|
|
|
- |
|
|
|
- |
|
|
Depreciation, depletion and amortization |
|
|
58,311 |
|
|
|
41,899 |
|
|
|
31,129 |
|
|
Impairment of oil and natural gas properties |
|
|
178,470 |
|
|
|
- |
|
|
|
- |
|
|
General and administrative |
|
|
23,425 |
|
|
|
18,912 |
|
|
|
14,909 |
|
|
Accretion expenses related to asset retirement obligation |
|
|
154 |
|
|
|
374 |
|
|
|
496 |
|
|
Total costs and expenses |
|
|
304,815 |
|
|
|
85,847 |
|
|
|
62,962 |
|
|
OPERATING INCOME (LOSS) |
|
|
(88,138 |
) |
|
|
39,942 |
|
|
|
19,983 |
|
|
OTHER INCOME AND EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
|
37,499 |
|
|
|
(1,366 |
) |
|
|
16,457 |
|
|
Loss on extinguishment of debt |
|
|
(5,689 |
) |
|
|
- |
|
|
|
(294 |
) |
|
Equity in income of Pinnacle Gas Resources, Inc. |
|
|
- |
|
|
|
- |
|
|
|
35 |
|
|
Interest income |
|
|
269 |
|
|
|
691 |
|
|
|
969 |
|
|
Interest expense |
|
|
(30,257 |
) |
|
|
(26,403 |
) |
|
|
(19,071 |
) |
|
Capitalized interest |
|
|
20,527 |
|
|
|
11,718 |
|
|
|
9,975 |
|
|
Other income, net |
|
|
17 |
|
|
|
130 |
|
|
|
427 |
|
|
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT) |
|
|
(65,772 |
) |
|
|
24,712 |
|
|
|
28,481 |
|
|
INCOME TAX EXPENSE (BENEFIT) |
|
|
(20,725 |
) |
|
|
9,243 |
|
|
|
10,233 |
|
|
NET INCOME (LOSS) |
|
$ |
(45,047 |
) |
|
$ |
15,469 |
|
|
$ |
18,248 |
|
|
OTHER COMPREHENSIVE INCOME (LOSS): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in market value of investment in Pinnacle Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources, Inc., net of taxes |
|
|
(6,724 |
) |
|
|
5,425 |
|
|
|
- |
|
|
COMPREHENSIVE INCOME (LOSS) |
|
$ |
(51,771 |
) |
|
$ |
20,894 |
|
|
$ |
18,248 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC EARNINGS (LOSS) PER COMMON SHARE |
|
$ |
(1.49 |
) |
|
$ |
0.58 |
|
|
$ |
0.73 |
|
|
DILUTED EARNINGS (LOSS) PER COMMON SHARE |
|
$ |
(1.49 |
) |
|
$ |
0.57 |
|
|
$ |
0.71 |
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC |
|
|
30,326 |
|
|
|
26,641 |
|
|
|
25,081 |
|
|
DILUTED |
|
|
30,326 |
|
|
|
27,120 |
|
|
|
25,565 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(As Restated and Adjusted (See Note 2))
| |
|
Common Stock |
|
|
|
|
Shares |
|
|
Amount |
|
|
|
|
(Dollars in thousands) |
|
|
BALANCE, January 1, 2006 |
|
|
24,251,430 |
|
|
$ |
243 |
|
|
Common stock issued, net of offering cost |
|
|
1,350,000 |
|
|
|
13 |
|
|
Common stock issued for property |
|
|
2,000 |
|
|
|
- |
|
|
Stock options exercised for cash |
|
|
101,800 |
|
|
|
1 |
|
|
Stock-based compensation |
|
|
- |
|
|
|
- |
|
|
Capitalization of repriced stock options of adoption of SFAS 123(R) |
|
|
- |
|
|
|
- |
|
|
Restricted stock awards, net of forfeitures |
|
|
277,436 |
|
|
|
3 |
|
|
Common stock repurchased for tax withholding obligations |
|
|
(2,061 |
) |
|
|
- |
|
|
Net income |
|
|
- |
|
|
|
- |
|
|
BALANCE, December 31, 2006 |
|
|
25,980,605 |
|
|
$ |
260 |
|
|
Common stock issued, net of offering cost |
|
|
1,800,000 |
|
|
|
18 |
|
|
Stock options exercised for cash |
|
|
124,148 |
|
|
|
1 |
|
|
Stock-based compensation |
|
|
- |
|
|
|
- |
|
|
Restricted stock awards, net of forfeitures |
|
|
111,839 |
|
|
|
1 |
|
|
Common stock repurchased for tax withholding obligations |
|
|
(7,440 |
) |
|
|
- |
|
|
Other comprehensive income: |
|
|
- |
|
|
|
- |
|
|
Fair value adjustment to investment in Pinnacle Gas Resources, Inc., net of tax |
|
|
|
|
|
|
|
|
|
Net income |
|
|
- |
|
|
|
- |
|
|
Total other comprehensive income |
|
|
- |
|
|
|
- |
|
|
BALANCE, December 31, 2007 |
|
|
28,009,152 |
|
|
$ |
280 |
|
|
Common stock issued, net of offering cost |
|
|
2,587,500 |
|
|
|
26 |
|
|
Bifurcation of equity premium related to Senior Secured Notes |
|
|
- |
|
|
|
- |
|
|
Stock options exercised for cash |
|
|
65,400 |
|
|
|
1 |
|
|
Stock-based compensation |
|
|
- |
|
|
|
- |
|
|
Restricted stock awards, net of forfeitures |
|
|
203,306 |
|
|
|
2 |
|
|
Common stock repurchased to settle tax withholding obligations |
|
|
(5,711 |
) |
|
|
- |
|
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
Fair value adjustment to investment in Pinnacle Gas Resources, Inc., net of tax |
|
|
- |
|
|
|
- |
|
|
Net loss |
|
|
- |
|
|
|
- |
|
|
Total other comprehensive loss |
|
|
- |
|
|
|
- |
|
|
BALANCE, December 31, 2008 |
|
|
30,859,647 |
|
|
$ |
309 |
|
| |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(As Restated and Adjusted (See Note 2))
| |
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
Paid in |
|
|
Retained |
|
|
Comprehensive |
|
|
Shareholders’ |
|
|
|
|
Capital |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Equity |
|
|
|
|
(Dollars in thousands) |
|
|
BALANCE, January 1, 2006 |
|
$ |
123,515 |
|
|
$ |
31,627 |
|
|
$ |
- |
|
|
$ |
155,385 |
|
|
Common stock issued, net of offering cost |
|
|
33,403 |
|
|
|
- |
|
|
|
- |
|
|
|
33,416 |
|
|
Common stock issued for property |
|
|
55 |
|
|
|
- |
|
|
|
- |
|
|
|
55 |
|
|
Stock options exercised for cash |
|
|
601 |
|
|
|
- |
|
|
|
- |
|
|
|
602 |
|
|
Stock-based compensation |
|
|
3,007 |
|
|
|
- |
|
|
|
- |
|
|
|
3,007 |
|
|
Capitalization of repriced stock options at adoption of SFAS 123(R) |
|
|
1,696 |
|
|
|
- |
|
|
|
- |
|
|
|
1,696 |
|
|
Restricted stock awards, net of forfeitures |
|
|
(80 |
) |
|
|
- |
|
|
|
- |
|
|
|
(77 |
) |
|
Common stock repurchased to settle tax withholding obligations |
|
|
(58 |
) |
|
|
- |
|
|
|
- |
|
|
|
(58 |
) |
|
Net income |
|
|
- |
|
|
|
18,248 |
|
|
|
- |
|
|
|
18,248 |
|
|
BALANCE, December 31, 2006 |
|
$ |
162,139 |
|
|
$ |
49,875 |
|
|
$ |
- |
|
|
$ |
212,274 |
|
|
Common stock issued, net of offering cost |
|
|
71,908 |
|
|
|
- |
|
|
|
- |
|
|
|
71,926 |
|
|
Stock options exercised for cash |
|
|
1,030 |
|
|
|
- |
|
|
|
- |
|
|
|
1,031 |
|
|
Stock-based compensation |
|
|
5,041 |
|
|
|
- |
|
|
|
- |
|
|
|
5,041 |
|
|
Restricted stock awards, net of forfeitures |
|
|
(136 |
) |
|
|
- |
|
|
|
- |
|
|
|
(135 |
) |
|
Common stock repurchased to settle tax withholding obligations |
|
|
(310 |
) |
|
|
- |
|
|
|
- |
|
|
|
(310 |
) |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value adjustment to investment in Pinnacle Gas Resources, |
|
|
- |
|
|
|
- |
|
|
|
5,425 |
|
|
|
5,425 |
|
|
Inc., net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
- |
|
|
|
15,469 |
|
|
|
- |
|
|
|
15,469 |
|
|
Total other comprehensive income |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
20,894 |
|
|
BALANCE, December 31, 2007 |
|
$ |
239,672 |
|
|
$ |
65,344 |
|
|
$ |
5,425 |
|
|
$ |
310,721 |
|
|
Common stock issued, net of offering cost |
|
|
135,049 |
|
|
|
- |
|
|
|
- |
|
|
|
135,075 |
|
|
Bifurcation of equity premium related to Senior Secured Notes |
|
|
40,207 |
|
|
|
- |
|
|
|
- |
|
|
|
40,207 |
|
|
Stock options exercised for cash |
|
|
261 |
|
|
|
- |
|
|
|
- |
|
|
|
262 |
|
|
Stock-based compensation |
|
|
6,013 |
|
|
|
- |
|
|
|
- |
|
|
|
6,013 |
|
|
Restricted stock awards, net of forfeitures |
|
|
(63 |
) |
|
|
- |
|
|
|
- |
|
|
|
(61 |
) |
|
Common stock repurchased to settle tax withholding obligations |
|
|
(361 |
) |
|
|
- |
|
|
|
- |
|
|
|
(361 |
) |
|
Other Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value adjustment to investment in Pinnacle Gas Resources, |
|
|
|
|
|
|
- |
|
|
|
(6,724 |
) |
|
|
(6,724 |
) |
|
Inc., net of tax |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
- |
|
|
|
(45,047 |
) |
|
|
- |
|
|
|
(45,047 |
) |
|
Total other comprehensive loss |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(51,771 |
) |
|
BALANCE, December 31, 2008 |
|
$ |
420,778 |
|
|
$ |
20,297 |
|
|
$ |
(1,299 |
) |
|
$ |
440,085 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(As Restated and Adjusted (See Note 2))
| |
|
For the Years Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
(45,047 |
) |
|
$ |
15,469 |
|
|
$ |
18,248 |
|
|
Adjustments to reconcile net income (loss) to net cash provided by |
|
|
|
|
|
|
|
|
|
|
|
|
|
operating activities — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
58,311 |
|
|
|
41,899 |
|
|
|
31,129 |
|
|
Impairment of oil and natural gas properties |
|
|
178,470 |
|
|
|
- |
|
|
|
- |
|
|
Fair value (gain) loss on derivative financial instruments |
|
|
(41,345 |
) |
|
|
7,377 |
|
|
|
(8,069 |
) |
|
Provision for allowance for doubtful accounts |
|
|
(166 |
) |
|
|
(209 |
) |
|
|
1,386 |
|
|
Accretion of discounts on asset retirement obligations and debt |
|
|
154 |
|
|
|
374 |
|
|
|
496 |
|
|
Loss on extinguishment of debt |
|
|
4,601 |
|
|
|
- |
|
|
|
294 |
|
|
Stock-based compensation |
|
|
5,952 |
|
|
|
4,907 |
|
|
|
2,930 |
|
|
Equity in income of Pinnacle Gas Resources, Inc. |
|
|
- |
|
|
|
- |
|
|
|
(35 |
) |
|
Deferred income taxes |
|
|
(20,920 |
) |
|
|
8,329 |
|
|
|
9,829 |
|
|
Amortization of equity premium associated with Senior Convertible Notes |
|
|
1,825 |
|
|
|
- |
|
|
|
- |
|
|
Other |
|
|
5,272 |
|
|
|
1,623 |
|
|
|
1,237 |
|
|
Changes in operating assets and liabilities — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
2,605 |
|
|
|
316 |
|
|
|
(2,178 |
) |
|
Other assets |
|
|
(3,661 |
) |
|
|
(210 |
) |
|
|
2,037 |
|
|
Accounts payable |
|
|
(1,476 |
) |
|
|
15,463 |
|
|
|
5,560 |
|
|
Accrued liabilities |
|
|
4,179 |
|
|
|
(107 |
) |
|
|
2,573 |
|
|
Net cash provided by operating activities |
|
|
148,754 |
|
|
|
95,231 |
|
|
|
65,437 |
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(571,291 |
) |
|
|
(247,003 |
) |
|
|
(201,773 |
) |
|
Change in capital expenditure accrual |
|
|
11,808 |
|
|
|
17,079 |
|
|
|
7,791 |
|
|
Proceeds from the sale of oil and natural gas properties |
|
|
3,259 |
|
|
|
1,505 |
|
|
|
38,319 |
|
|
Advances to operators |
|
|
776 |
|
|
|
994 |
|
|
|
(517 |
) |
|
Advances for joint operations |
|
|
2,943 |
|
|
|
(229 |
) |
|
|
(4,786 |
) |
|
Other |
|
|
(2,840 |
) |
|
|
(70 |
) |
|
|
(610 |
) |
|
Net cash used in investing activities |
|
|
(555,345 |
) |
|
|
(227,724 |
) |
|
|
(161,576 |
) |
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from common stock issuances: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Private placements, net of offering costs |
|
|
135,075 |
|
|
|
71,926 |
|
|
|
33,525 |
|
|
Stock option exercises |
|
|
262 |
|
|
|
1,031 |
|
|
|
602 |
|
|
Net proceeds from debt issuance and borrowings |
|
|
778,182 |
|
|
|
174,000 |
|
|
|
80,000 |
|
|
Debt repayments |
|
|
(498,923 |
) |
|
|
(108,258 |
) |
|
|
(40,536 |
) |
|
Deferred loan costs and other |
|
|
(10,847 |
) |
|
|
(3,588 |
) |
|
|
(769 |
) |
|
Net cash provided by financing activities |
|
|
403,749 |
|
|
|
135,111 |
|
|
|
72,822 |
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
|
|
(2,842 |
) |
|
|
2,618 |
|
|
|
(23,317 |
) |
|
CASH AND CASH EQUIVALENTS, beginning of year |
|
|
8,026 |
|
|
|
5,408 |
|
|
|
28,725 |
|
|
CASH AND CASH EQUIVALENTS, end of year |
|
$ |
5,184 |
|
|
$ |
8,026 |
|
|
$ |
5,408 |
|
|
SUPPLEMENTAL CASH FLOW DISCLOSURES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest (net of amounts capitalized) |
|
$ |
4,160 |
|
|
$ |
12,217 |
|
|
$ |
7,211 |
|
|
Cash paid for income taxes |
|
$ |
30 |
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo” or the “Company”) is an independent energy company engaged in the exploration, development and production of natural gas and oil. Our current operations are principally focused in proven, producing natural gas plays known as “shale plays” or
“resource plays”. The Company’s primary core area is the Barnett Shale area in North Texas (“Barnett Shale” or “Fort Worth Barnett Shale”), with a focus on Southeast Tarrant County, Texas. Through its wholly-owned subsidiary Carrizo (Marcellus) LLC, the Company is also actively seeking to establish a core area in another emerging resource play, the Marcellus Shale play in Pennsylvania, New York, West Virginia and Virginia. In addition to the Barnett and the Marcellus,
we are active in other shale plays, including the Fayetteville in Arkansas, Barnett/Woodford in West Texas/New Mexico, Floyd/Neal in Mississippi, and the New Albany in Kentucky/Illinois. We also explore for, develop and produce natural gas and oil from traditional geologic trends along the onshore Gulf Coast area in Texas, Louisiana and Alabama, primarily in the Miocene, Wilcox, Frio and Vicksburg trends. The Company’s other interests include properties in the U.K. North Sea.
2. ADJUSTMENTS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Restatement for 2008 Ceiling Test Impairment and Adjustment for Retrospective Application of FSP APB 14-1 and FSP EITF 03-6-1
Subsequent to filing the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, an error was discovered in the ceiling test computation. The Company determined that its impairment calculation did not take into account correctly certain deferred tax amounts and the classification of costs between the
unevaluated costs and the full cost pool. As a result, the Company is restating its consolidated financial information for the year ended December 31, 2008 in this Form 10-K/A. The effect of this restatement is an increase of the ceiling test impairment from $138.6 million to $178.5 million as of December 31 2008.
Furthermore, the Company has adjusted its consolidated financial statements for the years ended December 31, 2008 to reflect the adoption of the Financial Accounting Standards Board's (“FASB”) Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible
Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)” (“APB 14-1”), and FSP Emerging Issues Task Force No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“EITF 03-6-1”) for all periods presented.
Effective on January 1, 2009, the Company adopted APB 14-1, which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. APB 14-1 requires that issuers of convertible debt separately account for the liability and equity components in a manner
that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Once adopted, APB 14-1 requires retrospective application to the terms of instruments as they existed for periods presented. The adoption of APB 14-1 affects the accounting for the Company’s 4.375% Senior Convertible Notes due 2028. The retrospective application of this accounting pronouncement affects the Company’s balance sheet as of December
31, 2008, and statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2008.
On January 1, 2009, the Company adopted and retroactively applied EITF 03-6-1. This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall
be included in the computation of both basic and diluted earnings per share. This FSP requires retroactive application for all periods presented. The Company determined that its restricted shares of common stock are participating securities as defined in this FSP and applied this FSP retroactively to all periods presented.
The following table sets forth the effect of the restatement of the 2008 ceiling test impairment and the retrospective application of APB 14-1 and EITF 03-6-1 on certain previously reported items:
| |
|
For the Years Ended December 31, |
|
| |
|
2008 |
|
|
2007 |
|
|
2006 |
|
| |
|
Originally Reported |
|
|
As Adjusted |
|
|
Originally Reported |
|
|
As Adjusted(1) |
|
|
Originally Reported |
|
|
As Adjusted(1) |
|
| |
|
(In thousands, except per share amounts) |
|
|
Impairment of oil and natural gas properties |
|
$ |
138,591 |
|
|
$ |
178,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(23,546 |
) |
|
|
(30,257 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest |
|
|
15,641 |
|
|
|
20,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE INCOME TAX EXPENSE |
|
|
(24,068 |
) |
|
|
(65,772 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX BENEFIT |
|
|
(6,129 |
) |
|
|
(20,725 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
|
|
(17,939 |
) |
|
|
(45,047 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE LOSS |
|
|
(24,663 |
) |
|
|
(51,771 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Income (Loss) Per Share |
|
$ |
(0.60 |
) |
|
$ |
(1.49 |
) |
|
$ |
0.59 |
|
|
$ |
0.58 |
|
|
$ |
0.74 |
|
|
$ |
0.73 |
|
|
Diluted Income (Loss) Per Share |
|
$ |
(0.60 |
) |
|
$ |
(1.49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Oustanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
30,010 |
|
|
|
30,326 |
|
|
|
26,287 |
|
|
|
26,641 |
|
|
|
24,827 |
|
|
|
25,081 |
|
|
Diluted |
|
|
30,010 |
|
|
|
30,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Adjusted for the retrospective adoption of EITF 03-6-1 only, as discussed above. |
Consolidated Balance Sheet:
| |
|
December 31, 2008 |
|
| |
|
Originally |
|
|
As |
|
| |
|
Reported |
|
|
Adjusted |
|
| |
|
(In thousands) |
|
|
Property and Equipment |
|
$ |
1,021,621 |
|
|
$ |
986,629 |
|
|
Deferred Financing Costs, net |
|
|
9,750 |
|
|
|
8,430 |
|
|
Long-Term Debt, net of current maturities |
|
|
533,057 |
|
|
|
475,788 |
|
|
and debt discount |
|
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
26,920 |
|
|
|
34,778 |
|
|
Additional Paid-In Capital |
|
|
380,571 |
|
|
|
420,778 |
|
|
Retained Earnings |
|
|
47,405 |
|
|
|
20,927 |
|
|
Total Shareholders' Equity |
|
|
426,986 |
|
|
|
440,085 |
|
In addition, the restatement and retrospective application resulted in changes to our consolidated statement of cash flows for the year ended December 31, 2008 and Notes 4, 5, 6 and 13.
Principles of Consolidation
The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances. The financial statements reflect necessary
adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.
Unconsolidated Investments
Prior to April 2006, the Company’s investment in Pinnacle Gas Resources, Inc. (“Pinnacle”) was recorded using the equity method of accounting and was adjusted for the Company’s equity in the subsidiary’s profit or loss. In April 2006, the Company changed its accounting for Pinnacle to the cost method of accounting
and adjusts the carrying amount of its investment for contributions to and distributions from the subsidiary.
In 2007, Pinnacle became a publicly traded entity on the Nasdaq Global Market. For accounting purposes, the Pinnacle common stock now has a readily determinable fair market value. The Company classifies the investment as available-for-sale and adjusts the book value to fair market value through other comprehensive income, net of taxes.
This fair value adjustment is assessed quarterly for other than temporary impairment based upon publicly available information. If the loss is deemed other than temporary, it will be recognized in earnings.
The Company accounts for its investment in Oxane Materials, Inc. using the cost method of accounting and adjusts the carrying amount of its investment for contributions to and distributions from the entity.
Reclassifications
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation. These reclassifications had no effect on total assets, total liabilities, shareholders’ equity or net income.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair
values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly,
reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability
to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term.
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company
proportionally consolidates its interests in oil and natural gas properties. The Company capitalized compensation costs and other costs of employees working directly on exploration activities of $7.8 million, $4.5 million and $3.5 million in 2008, 2007 and 2006, respectively. Maintenance and repairs are expensed as incurred.
Depreciation, depletion and amortization (“DD&A”) of proved oil and natural gas properties are based on the unit-of-production method using estimates of proved reserve quantities. Costs not subject to amortization include costs of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and
exploratory wells in progress. These costs are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties have been impaired, the amount of such impairment is determined and added to the proved oil and natural gas property costs subject to DD&A. The depletable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion
rate per Mcfe for 2008, 2007 and 2006 was $2.23, $2.36 and $2.61, respectively.
Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.
The net capitalized costs are limited to a “ceiling test” based on the estimated future net revenues from proved reserves, discounted at a 10% rate per annum, based on current economic and operating conditions (“full cost ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings. During
2008, the Company recorded an impairment of $178.5 million associated with its year end 2008 ceiling test analysis.
Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are estimates prepared by Ryder Scott Company Petroleum Engineers, Fairchild & Wells, Inc. and LaRoche Petroleum Consultants, Ltd., independent petroleum engineers. Reserve engineering is a subjective process
of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value
discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than the Company’s estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates
may be made depending on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on market prices and costs on the date of the estimate.
The Company’s rate of recording depreciation, depletion and amortization expense for proved properties is dependent on the Company’s estimate of proved reserves. If these reserve estimates decline, the rate at which the Company records these expenses will increase.
The Company’s full cost ceiling test also depends on the Company’s estimate of proved reserves. If these reserve estimates decline, the Company may be subjected to a full cost ceiling write-down. The Company recorded a full cost ceiling test write-down in 2008.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with maturities of three months or less when purchased.
Revenue Recognition and Natural Gas Imbalances
The Company follows the sales method of accounting for revenue recognition and natural gas imbalances, which recognizes over and under lifts of natural gas when sold, to the extent sufficient natural gas reserves or balancing agreements are in place. Natural gas, natural gas liquids and oil sales volumes are not significantly different
from the Company’s share of production.
The Company purchases natural gas at the well head from a third-party operator under a purchase and sales agreement whereby the Company recognizes revenue at the redelivery point, which is the point at which title to the natural gas transfers to the purchaser. The Company then remits the sales proceeds received less a fixed fee per unit
of production (MMBtu) transported which is recorded at the cost of the natural gas purchased.
Financing Costs, net
Net long-term debt financing costs of $8.4 million (net of $10.4 million accumulated amortization) and $5.9 million (net of $4.0 million accumulated amortization) were capitalized as of December 31, 2008 and 2007, respectively, and are being amortized using the effective yield method over the term of the debt, which is through May 2013
for the Convertible Senior Notes and through October 2012 for the Senior Secured Revolving Credit Facility.
Supplemental Cash Flow Information
The Statement of Cash Flows for the year ended December 31, 2008 does not include the adjustment of the investment in Pinnacle of $(6.7) million, net of tax. The Statement of Cash Flows for the year ended December 31, 2007 does not include the adjustment of the investment in Pinnacle of $5.4 million, net of tax. The Statement of Cash Flows
for the year ended December 31, 2006 does not include the acquisition of $55,000 of oil and gas properties in exchange for the Company’s common stock and the capitalization of stock-based compensation associated with the adoption of SFAS 123(R) of $1.7 million, net of tax.
Financial Instruments
The Company’s financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amounts of long-term debt under the Senior Credit Facility approximate fair value as these borrowings
bear interest at variable interest rates. The carrying amount of the Convertible Senior Notes does not approximate fair value because the notes are fixed rate debt.
Stock-Based Compensation
In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the “Incentive Plan”), which authorizes the granting of stock options and stock awards to directors, employees and independent contractors. The Company recognized the following stock-based compensation expenses for the years ended December
31:
| |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In millions) |
|
|
Stock Option |
|
$ |
0.1 |
|
|
$ |
0.3 |
|
|
$ |
0.5 |
|
|
Restricted Stock |
|
|
5.9 |
|
|
|
4.6 |
|
|
|
2.4 |
|
|
Total Stock-Based Compensation |
|
$ |
6.0 |
|
|
$ |
4.9 |
|
|
$ |
2.9 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options. Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS
No. 123(R)”), which requires companies to measure all stock-based compensation awards using the fair value method and record such expense in the financial statements over the vesting period of the options, which is generally three years. The Company implemented SFAS No. 123(R) using the modified prospective transition method.
The Company recognizes compensation expense for all unvested options outstanding as of January 1, 2006, options issued after January 1, 2006, and those options that are subsequently modified, repurchased or cancelled. The compensation expense is based on the grant-date fair value of the options and expensed over the vesting period.
The Company uses the Black-Scholes option pricing model to compute the fair value of stock options, which requires the Company to make the following assumptions:
|
|
• |
The risk-free interest rate is based on the five-year Treasury bond at date of grant. |
|
|
• |
The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future. |
|
|
• |
The market price volatility of the Company’s common stock is based on daily, historical prices for the last three years. |
|
|
• |
The term of the grants is based on the simplified method as described in Staff Accounting Bulletin No. 107. |
In addition, the Company estimates a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures becomes available.
Restricted Stock. The Company grants shares of restricted stock and measures deferred compensation based on the price of the Company’s stock on the grant date. The deferred compensation is amortized to stock-based compensation expense ratably over
the vesting period of the restricted shares (generally one to three years), using either the straight-line or graded vesting method as prescribed in SFAS 123(R). Restricted stock issued to other than employees that vests over time as services are provided is adjusted to fair value at each reporting period with the change in fair value being recorded to expense until vested.
Taxes. Upon settlement of stock awards, the Company recognizes any difference between book compensation expense and tax compensation expense as a tax windfall or shortfall. The difference is charged to equity in the case of a windfall. In the case of shortfalls,
the difference is charged to equity to the extent of previously recognized windfall tax benefits and any remaining shortfall is recognized as additional income tax expense. When the settlement of an award results in a net operating loss (NOL), or increases an NOL carryforward, SFAS 123(R) prescribes that no windfall should be recognized until the deduction reduces income tax payable. At December 31, 2008, the Company had an NOL of approximately $67.5 million. The Company has postponed the recognition of approximately
$5.7 million in windfall tax benefits associated with its stock-based compensation until a tax cash savings is realized.
Derivative Instruments
The Company uses derivatives to manage price risk underlying its oil and natural gas production. The Company also used derivatives to manage the variable interest rate on its Second Lien Credit Facility that was terminated in May 2008.
Upon entering into a derivative contract, the Company either designates the derivative instrument as a hedge of the variability of cash flow to be received (cash flow hedge) or the derivative must be accounted for as a non-designated derivative. All of the Company’s derivative instruments during the years ended December 31, 2008,
2007 and 2006 were treated as non-designated derivatives and the unrealized gain/(loss) related to the change in mark-to-market valuation was included in the Company’s earnings.
The Company typically uses fixed-rate swaps, costless collars and basis differential swaps to hedge its exposure to material changes in the price of oil and natural gas and variable interest rates on long-term debt.
The Company’s Board of Directors sets all risk management policies and reviews volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial
Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities quarterly.
Income Taxes
Under SFAS No. 109 “Accounting for Income Taxes,” deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory
tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assess the realizability of its deferred tax assets and considers future taxable income in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite the Company’s attempt to make an accurate estimate, the
ultimate utilization of the deferred tax assets is highly dependent upon actual production and the realization of taxable income in future periods.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable result from oil and natural gas sales, joint interest billings to third parties in the oil and natural gas industry or drilling and completion advances to third-party operators for development costs of in-progress wells. This concentration of customers and joint interest owners
may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.
Derivative contracts subject the Company to a concentration of credit risk. At December 31, 2008, approximately 69% of the Company’s open natural gas hedges were with Credit Suisse, and the remaining 31% were with Shell Energy North America (US), L.P. The open oil hedge positions were all arranged with Credit Suisse. The Company
maintains its cash with major U.S. banks and one bank in the United Kingdom. From time to time, cash amounts may exceed the FDIC insured limit of $250,000. The terms of these deposits are on demand to minimize risk. Historically, the Company has not incurred losses related to these deposits.
Allowance for Doubtful Accounts
The Company establishes provisions for losses on accounts receivable when it determines that it will not collect all or a part of the outstanding balance. The Company reviews collectability quarterly and adjusts the allowance as necessary using the specific identification method.
During the fourth quarter of 2006, Reichmann Petroleum filed for bankruptcy. At the time, the Company had outstanding receivable balances of approximately $1.5 million for October 2006 production and advances to Reichmann for the drilling of wells in which Reichmann was the operator. The Company expects to recover approximately five percent
of the receivable balance due at the time of bankruptcy. Accordingly, the Company increased the allowance by approximately $1.5 million during the fourth quarter of 2006. During 2007, the Company collected the receivable associated with October 2006 production and reduced the reserve for the Reichmann bankruptcy to $0.9 million.
Major Customers
The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
DTE Energy Trading, Inc. |
|
|
39 |
% |
|
|
- |
|
|
|
- |
|
|
Cokinos Natural Gas Company |
|
|
11 |
% |
|
|
11 |
% |
|
|
- |
|
|
Crosstex Energy |
|
|
10 |
% |
|
|
15 |
% |
|
|
- |
|
|
Houston Pipeline Company |
|
|
- |
|
|
|
11 |
% |
|
|
- |
|
|
Energy Transfer |
|
|
- |
|
|
|
10 |
% |
|
|
- |
|
|
Reichmann Petroleum |
|
|
- |
|
|
|
- |
|
|
|
10 |
% |
|
Chevron/Texaco |
|
|
- |
|
|
|
- |
|
|
|
11 |
% |
Earnings Per Share
Supplemental earnings per share information is provided below:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
| |
|
Adjusted |
|
|
|
|
(In thousands, except per share amounts) |
|
|
Net income (loss) available to common shareholders |
|
$ |
(45,047 |
) |
|
$ |
15,469 |
|
|
$ |
18,248 |
|
|
Basic weighted average common shares outstanding |
|
|
30,326 |
|
|
|
26,641 |
|
|
|
25,081 |
|
|
Stock options |
|
|
- |
|
|
|
479 |
|
|
|
484 |
|
|
Diluted weighted average shares outstanding |
|
|
30,326 |
|
|
|
27,120 |
|
|
|
25,565 |
|
|
Earnings (loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.49 |
) |
|
$ |
0.58 |
|
|
$ |
0.73 |
|
|
Diluted |
|
$ |
(1.49 |
) |
|
$ |
0.57 |
|
|
$ |
0.71 |
|
Basic earnings (loss) per common share is based on the weighted average number of shares of common stock outstanding during the periods including unvested restricted shares subject to the provisions of EITF 03-6-1. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential
common shares outstanding during the periods. The Company had outstanding 685,854 stock options at December 31, 2008 that were antidilutive due to the net loss for 2008. Shares subject to potential issuance upon conversion of the Convertible Senior Notes did not have any impact on the calculation for 2008. The Company had 2,500 stock options at December 31, 2006 that were antidilutive as the exercise price of the options was greater than the then current market price of the Company’s stock.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
Asset Retirement Obligation
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). SFAS No. 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible
long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The ARO is recorded at fair value, excluding salvage values, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free
interest rate. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.
In accordance with the provisions of SFAS No. 143, the Company records an abandonment liability associated with its oil and natural gas wells when those assets are placed in service. Under SFAS No. 143, depletion expense is reduced since a discounted ARO is depleted in the property balance rather than the undiscounted value previously
depleted under the old rules. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which is recognized over time as the discounted liability is accreted to its expected settlement value.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact
the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Settlements greater than or less than amounts accrued as ARO are recovered as a gain or loss upon settlement.
The following table is a reconciliation of the asset retirement obligation liability for the years ended December 31:
| |
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Asset retirement obligation at beginning of year |
|
$ |
5,869 |
|
|
$ |
3,625 |
|
|
Liabilities incurred |
|
|
1,004 |
|
|
|
1,251 |
|
|
Liabilities settled |
|
|
(177 |
) |
|
|
(234 |
) |
|
Accretion expense |
|
|
154 |
|
|
|
374 |
|
|
Revisions to previous estimates |
|
|
(347 |
) |
|
|
853 |
|
|
Asset retirement obligation at end of year |
|
$ |
6,503 |
|
|
$ |
5,869 |
|
| |
|
|
|
|
|
|
|
|
Foreign Currency
The company has foreign activities related to its operations in the U.K. North Sea. Accordingly, assets and liabilities related to these operations are translated into United States dollars at exchange rates in effect at the balance sheet date. Income and expense items are translated at average exchange rates throughout the year. Translation
adjustments are charged or credited to other comprehensive income (loss) and are recorded net of applicable taxes. Transaction gains or losses that occur due to the realization of assets and the settlement of liabilities using a currency denominated in other than the functional currency are charged to earnings.
Recently Issued Accounting Pronouncements
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring
transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company does not believe
the adoption of SFAS No. 161 will have a significant effect on its consolidated financial position, results of operations or cash flows.
On December 31, 2008, the Securities and Exchange Commission (SEC) adopted a major revision to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors.
The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that the net present value of oil and gas reserves to be reported and used in the full-cost ceiling test calculation should be based upon an average
price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.
Recently Adopted Accounting Pronouncements
The Company adopted the Financial Accounting Standards Statement No. 157, “Fair Value Measurement” (“SFAS No. 157”), effective January 1, 2008. SFAS No. 157 provides a framework for measuring fair value
and enhances related disclosures. The implementation of SFAS No. 157 did not change the Company’s current valuation method and did not have a material effect on the Company’s consolidated financial position or results of operations. The Company included additional disclosures in the Notes to Consolidated Financial Statements with respect to the measurement of its assets and liabilities at fair value on the balance sheet date.
The Company adopted APB 14-1 effective January 1, 2009. This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible
Debt and Debt Issued with Stock Purchase Warrants.” Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company valued the 4.375% Senior Convertible Notes due 2028 as $309.6 million of debt and $64.2 million of equity, representing
the fair value of the
conversion premium on the date of issuance, and recognized an additional $1.8 million in interest expense (net of $4.9 million capitalized to oil and natural gas properties) during 2008, resulting in an effective interest rate of approximately 8% for 2008.
The Company adopted EITF 03-6-1 effective January 1, 2009. This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share.
The Company determined that some of its shares of restricted stock qualified as participating securities and included them in both basic and diluted earnings per share calculation for all periods presented.
3. INVESTMENTS
Investments consisted of the following at December 31, 2008 and 2007:
| |
|
December 31, |
|
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Pinnacle Gas Resources, Inc. |
|
$ |
751 |
|
|
$ |
11,071 |
|
|
Oxane Materials, Inc. |
|
|
2,523 |
|
|
|
- |
|
| |
|
$ |
3,274 |
|
|
$ |
11,071 |
|
| |
|
|
|
|
|
|
|
|
Pinnacle Gas Resources, Inc.
In 2003, the Company’s wholly-owned subsidiary CCBM, Inc. (“CCBM”) contributed its interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”).
The Company classifies the Pinnacle investment as available-for-sale and adjusts the investment to fair value through Other Comprehensive Income. At December 31, 2008, the Company reported the fair value of the stock at $0.8 million (based on the closing price of Pinnacle’s common stock on December 31, 2008), which is approximately
$2.0 million below original cost. The fair value of this investment based on quoted market prices, was in excess of or equal to the original cost in October 2008. Management believes that this recent decrease in value that commenced in October of 2008 is temporary.
In June 2007, the Company sold 41,894 shares of Pinnacle stock for net proceeds of $0.4 million and recognized a $0.3 million gain, which is included in other income and expenses, net on the Consolidated Statements of Operations. As of December 31, 2008, the Company owned 2,422,238 shares of Pinnacle common stock.
Oxane Materials, Inc.
In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program. The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase
Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane. The convertible promissory note accrued interest at a rate of 6% per annum. During the fourth quarter of 2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock. The Company accounts for the investment using the cost method.
4. PROPERTY AND EQUIPMENT
At December 31, 2008 and 2007, property and equipment consisted of the following:
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Proved oil and natural gas properties |
|
$ |
821,238 |
|
|
$ |
655,308 |
|
|
Costs not subject to amortization |
|
|
378,634 |
|
|
|
170,586 |
|
|
Land, building and other equipment |
|
|
6,363 |
|
|
|
2,853 |
|
|
Total property and equipment |
|
|
1,206,235 |
|
|
|
828,747 |
|
|
Accumulated depreciation, depletion and amortization |
|
|
(219,606 |
) |
|
|
(181,937 |
) |
|
Property and equipment, net |
|
$ |
986,629 |
|
|
$ |
646,810 |
|
| |
|
|
|
|
|
|
|
|
Oil and natural gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and exploratory wells in progress. These costs are reviewed periodically by
management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production
response to secondary recovery activities and available funds for exploration and development. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to five years.
The significant decline in oil and natural gas prices caused the discounted present value (discounted at 10 percent) of future net cash flows from proved oil and gas reserves to fall below the net book basis of the proved oil and gas properties. This resulted in a non-cash ceiling test write-down at the end of the fourth quarter of 2008
of $178.5 million ($116.0 million after tax).
5. INCOME TAXES
All of the Company’s income is derived from domestic activities. Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35% to pretax income as follows:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
Provision at the statutory tax rate |
|
$ |
(23,020 |
) |
|
$ |
8,649 |
|
|
$ |
9,968 |
|
|
Preferred dividend on Pinnacle |
|
|
- |
|
|
|
- |
|
|
|
141 |
|
|
Increase in valuation allowance for equity in income of Pinnacle |
|
|
- |
|
|
|
- |
|
|
|
(153 |
) |
|
State taxes |
|
|
123 |
|
|
|
594 |
|
|
|
277 |
|
|
Nondeductible expenses |
|
|
1,930 |
|
|
|
- |
|
|
|
- |
|
|
Other |
|
|
242 |
|
|
|
- |
|
|
|
- |
|
|
Income tax expense (benefit) |
|
$ |
(20,725 |
) |
|
$ |
9,243 |
|
|
$ |
10,233 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes result from temporary differences in the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 2008 and 2007, the tax effects of these temporary differences resulted principally from the following:
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Deferred income tax assets: |
|
|
|
|
|
|
|
Net operating loss carryforward |
|
$ |
23,547 |
|
|
$ |
17,430 |
|
|
Stock based compensation |
|
|
1,549 |
|
|
|
1,675 |
|
|
Fair value derivative instruments |
|
|
- |
|
|
|
1,332 |
|
|
Allowance for doubtful accounts |
|
|
442 |
|
|
|
500 |
|
|
Equity in income of Pinnacle |
|
|
385 |
|
|
|
385 |
|
|
Valuation allowance |
|
|
(385 |
) |
|
|
(385 |
) |
|
Adjustmennt to fair value of investment in Pinnacle |
|
|
699 |
|
|
|
- |
|
| |
|
|
26,237 |
|
|
|
20,937 |
|
|
Deferred income tax liabilities: |
|
|
|
|
|
|
|
|
|
Oil and gas acquisition, exploration and development |
|
|
12,740 |
|
|
|
48,010 |
|
|
costs deducted for tax purposes in excess of financial |
|
|
|
|
|
|
statement DD&A |
|
|
|
|
|
|
|
|
|
Conversion premium on convertible debt |
|
|
20,044 |
|
|
|
- |
|
|
Capitalized interest |
|
|
22,520 |
|
|
|
15,335 |
|
|
Adjustment to fair value of investment in Pinnacle |
|
|
- |
|
|
|
2,921 |
|
|
Fair value derivative instruments |
|
|
14,659 |
|
|
|
668 |
|
|
Other |
|
|
155 |
|
|
|
- |
|
| |
|
|
70,118 |
|
|
|
66,934 |
|
|
Net deferred income tax liability |
|
$ |
43,881 |
|
|
$ |
45,997 |
|
| |
|
|
|
|
|
|
|
|
At December 31, 2008 and 2007, the net deferred income tax liability is classified as follows:
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Current deferred tax asset |
|
$ |
- |
|
|
$ |
(324 |
) |
|
Current deferred tax liability |
|
|
9,103 |
|
|
|
- |
|
|
Deferred income taxes |
|
|
34,778 |
|
|
|
46,321 |
|
|
Deferred income tax liability, net |
|
$ |
43,881 |
|
|
$ |
45,997 |
|
| |
|
|
|
|
|
|
|
|
The realization of deferred tax assets is dependent on the Company’s ability to generate taxable earnings in the future. The Company believes it will generate taxable income in the NOL carryforward period. As such management believes that it is more likely than not that its deferred tax assets other than the deferred tax asset attributable
to Pinnacle will be fully realized. A full valuation allowance has been established for the equity in loss of Pinnacle’s tax asset as the realization of the deferred tax asset is dependent on generating sufficient taxable income in Pinnacle in future periods, which management believes is unlikely. The Company has a net operating loss carryforward totaling approximately $67.3 million, which is scheduled to expire over a period from 2019 through 2028.
On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 prescribes a measurement
process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company classifies interest and penalties associated with income taxes as interest expense. At December 31, 2008, the Company had no material uncertain tax positions and the tax years 2003 through
2007 remained open to review by federal and various state tax jurisdictions.
6. LONG-TERM DEBT
At December 31, 2008 and 2007, long-term debt consisted of the following:
| |
|
December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
|
|
(In thousands) |
|
|
Convertible Senior Notes |
|
$ |
373,750 |
|
|
$ |
- |
|
|
Unamortized discount for Convertible Senior Notes |
|
|
(57,269 |
) |
|
|
- |
|
|
Senior Secured Revolving Credit Facility |
|
|
159,000 |
|
|
|
34,000 |
|
|
Second Lien Credit Facility |
|
|
- |
|
|
|
220,500 |
|
|
Other |
|
|
480 |
|
|
|
1 |
|
| |
|
|
475,961 |
|
|
|
254,501 |
|
|
Less: current maturities |
|
|
(173 |
) |
|
|
(2,251 |
) |
| |
|
$ |
475,788 |
|
|
$ |
252,250 |
|
| |
|
|
|
|
|
|
|
|
Convertible Senior Notes
In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process, into a combination of cash
and Carrizo common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of Carrizo’s conversion obligation in excess of such principal amount. The notes are convertible into Carrizo’s common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain
corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). Holders may convert the notes only under the following conditions:
(a) during any calendar quarter if the last reported sale price of Carrizo common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified
periods if specified distributions to holders of Carrizo common stock are made or specified corporate transactions occur, (d) prior to the close of
business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028. The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1,
2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.
The Convertible Senior Notes are subject to customary, non-financial covenant and events of default, including a cross default under the Senior Credit Facility, the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.
The Convertible Senior Notes are unsecured obligations of the Company and rank equal to all future senior unsecured debt but rank second in priority to the Senior Secured Revolving Credit Facility.
As prescribed by APB 14-1, on the date of issuance the Company valued the Convertible Senior Notes as $309.6 million of debt and $64.2 million of equity, representing the fair value of the conversion premium. The resulting debt discount will be amortized to interest expense through June 1, 2013, the first date on which the holders
may require the Company to repurchase the Convertible Senior Notes, resulting in an effective interest rate of approximately 8% for the Convertible Senior Notes.
Senior Secured Revolving Credit Facility
On May 25, 2006, the Company entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent. The Senior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured
by substantially all of the Company’s proved oil & gas assets and is guaranteed by the Company’s subsidiaries, CCBM, Inc., CLLR, Inc., Carrizo (Marcellus) LLC and Carrizo Marcellus Holdings, Inc.
In the fourth quarter of 2008, the Company amended the Senior Credit Facility to (1) increase the borrowing base to $250.0 million; (2) extend the maturity date to October 29, 2012; (3) increase the maximum total net debt to Consolidated EBITDAX to 4.0 to 1.0; (4) change the semi-annual borrowing base redetermination dates to March 31
and September 30; (5) change the interest rate provisions; and (6) replace JPMorgan Chase Bank with Guaranty Bank as the administrative agent bank.
If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, the Company has the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient
in the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.
The annual interest rate on each base rate borrowing is (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 0.75% and 2.25% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the
adjusted Daily LIBO rate on such day plus a margin between 2.0% to 3.5% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted daily LIBO rate plus a margin between 2.0% to 3.5% (depending on the then-current level of borrowing base usage). At December 31, 2008, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.0%.
The Company is subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.0 to 1.0; and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of 4.0
to 1.0. Although the Company currently believes that it can comply with all of the financial covenants with the business plan that it has put in place, the business plan is based on a number of assumptions, the most important of which is a relatively stable, natural gas price at economically sustainable levels. If the price that the Company receives for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to
a default under certain financial covenants in the Senior Credit Facility, including the financial covenants discussed above. In order to provide a further margin of comfort with regards to these financial covenants, the Company may seek to further reduce its capital and exploration budget, sell non-strategic assets, opportunistically modify or increase its natural gas hedges or approach the lenders under our Senior Credit Facility for modifications of either or both of the financial covenants discussed above.
There can be no assurance that the Company will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our Senior Credit Facility if a precipitous decline in natural gas prices were to occur in the future. The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions,
transactions with affiliates and other matters.
The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.
At December 31, 2008, the Company was in compliance with all of our debt covenants.
At December 31, 2008, the Company had $159.0 million of borrowings outstanding under the Senior Credit Facility and the borrowing base availability was $91.0 million.
Second Lien Credit Facility
On July 21, 2005, the Company entered into a Second Lien Credit Agreement with Credit Suisse, as administrative agent and collateral agent and the lenders party thereto (the “Second Lien Credit Facility”). The Second Lien Credit Facility, as amended, provided for a term loan facility in an aggregate principal amount of $225.0
million. In May 2008, the Company repaid in full the $219.9 million outstanding under the Second Lien Credit Facility and terminated the facility in connection with the issuance of its Convertible Senior Notes. The Company recorded a loss on extinguishment of approximately $5.7 million during 2008.
7. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations
and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.
The Company has a long-term operating lease agreement for its corporate offices that expires in December 2011. Under the terms of the lease agreement, the Company received a rent abatement equal to six months of lease payments and a build out allowance that is being amortized to expense over the term of the lease. In July 2006, the Company
amended its lease agreement to expand the leased office space by an additional floor. The lease term for the additional floor also expires in December 2011. Rent expense for the years ended December 31, 2008, 2007 and 2006 was $0.9 million, $0.9 million and $0.6 million, respectively, and includes rent expense for the Company’s corporate office and a field office in the Barnett Shale area.
Minimum office rentals, drilling rig obligations and pipeline volume commitments for each of the five years subsequent to December 31, 2008 are as follows (in thousands):
| |
|
Amount |
|
|
|
|
(in thousands) |
|
|
2009 |
|
$ |
32,575 |
|
|
2010 |
|
|
33,540 |
|
|
2011 |
|
|
15,929 |
|
|
2012 |
|
|
5,858 |
|
|
2013 and Thereafter |
|
|
21,223 |
|
| |
|
$ |
109,125 |
|
| |
|
|
|
|
|
8. |
SHAREHOLDERS’ EQUITY AND STOCK INCENTIVE PLAN |
Shareholders’ Equity
The following is a summary of changes in the Company’s common stock shares for the years ended December 31,:
| |
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
Shares outstanding at January 1 |
|
|
28,009 |
|
|
|
25,981 |
|
|
|
24,251 |
|
|
Common stock issued |
|
|
2,588 |
|
|
|
1,800 |
|
|
|
1,350 |
|
|
Restricted stock issued, net of forfeitures |
|
|
203 |
|
|
|
112 |
|
|
|
278 |
|
|
Stock options exercised |
|
|
65 |
|
|
|
124 |
|
|
|
102 |
|
|
Common stock issued for property |
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
Common stock repurchased and retired |
|
|
|
|
|
|
|
|
|
|
|
|
|
for tax withholding obligation |
|
|
(5 |
) |
|
|
(8 |
) |
|
|
(2 |
) |
|
Shares outstanding at December 31 |
|
|
30,860 |
|
|
|
28,009 |
|
|
|
25,981 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
In February 2008, the Company completed an underwritten public offering of 2,587,500 shares of its common stock at a price of $54.50 per share. The number of shares sold was approximately 9.2% of the Company’s outstanding shares before the offering. The Company received proceeds of approximately $135.1 million, net of expenses, which
were used to fund a portion of the Company’s 2008 capital expenditure program.
In September 2007, the Company sold 1.8 million shares of its common stock to certain qualified investors in a registered direct offering at a price of $41.40 per share. The number of shares sold was approximately 6.8% of the Company’s fully diluted shares outstanding before the offering. The Company used substantially all of the
net proceeds to fund in part its capital expenditure program, including its drilling and leasing programs in the Barnett Shale and appraisal well drilling in the North Sea. Pending those uses, the Company used a portion of the net proceeds of approximately $72.0 million to repay $54 million of outstanding borrowings under the Senior Credit Facility.
In July 2006, the Company sold 1.35 million shares of the Company’s common stock to institutional investors at a price of $26.00 per share in a private placement. The number of shares sold was approximately 5.4% of the Company’s fully diluted shares outstanding before the offering. The net proceeds, after deducting placement
agents’ fees but before paying offering expenses, of approximately $33.7 million were principally used to fund a portion of the Company’s 2006 capital expenditures program.
Stock Incentive Plan
In June 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the “Incentive Plan”), which authorizes the granting of stock options and restricted stock awards to directors, employees and independent contractors. The Company may grant awards of up to 2,800,000 shares under the Incentive Plan and has
granted options, restricted stock and restricted stock units covering 2,559,658 shares through December 31, 2008, net of forfeitures.
Stock Options. Prior to 2006, the Company issued stock options that become exercisable ratably over a three year period and expire ten years from the date of the grant. The table below summarizes stock option activity for the three years ended December 31, 2008:
| |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
|
|
|
|
Exercise |
|
|
Life |
|
|
Value |
|
|
|
|
Shares |
|
|
Prices |
|
|
(In years) |
|
|
(In millions) |
|
|
For the Year Ended December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period |
|
|
1,025,204 |
|
|
$ |
5.53 |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(101,800 |
) |
|
|
5.91 |
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(32,335 |
) |
|
|
12.63 |
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period |
|
|
891,069 |
|
|
$ |
5.25 |
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period |
|
|
834,799 |
|
|
$ |
4.65 |
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period |
|
|
891,069 |
|
|
$ |
5.25 |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(124,148 |
) |
|
|
8.30 |
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(5,000 |
) |
|
|
16.35 |
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period |
|
|
761,921 |
|
|
$ |
4.67 |
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period |
|
|
731,808 |
|
|
$ |
4.23 |
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period |
|
|
761,921 |
|
|
$ |
4.67 |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(65,400 |
) |
|
|
4.01 |
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(10,667 |
) |
|
|
6.72 |
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period |
|
|
685,854 |
|
|
$ |
4.71 |
|
|
|
3.0 |
|
|
$ |
7.0 |
|
|
Exercisable, end of period |
|
|
685,854 |
|
|
$ |
4.71 |
|
|
|
3.0 |
|
|
$ |
7.0 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008, the Company had no unrecognized expense associated with nonvested stock option awards. The total intrinsic value (current market price less the option strike price) of options exercised during the years ended December 31, 2008, 2007 and 2006 was $2.5 million, $4.5 million and $2.5 million, respectively, and the Company
received $0.3 million, $1.0 million and $0.6 million in cash in connection with these exercises for the years ended December 31, 2008, 2007 and 2006, respectively.
Restricted Stock Shares. The Company began issuing shares of restricted common stock in 2005 and restricted stock units in 2008. A restricted stock unit is an obligation to issue shares of stock upon their vesting. Unvested restricted stock awards are deemed issued and outstanding
based on the terms of the award. Restricted stock shares and units are accounted for as deferred compensation based on the closing price of the Company’s common stock on the grant date and are amortized to stock-based compensation expense over the vesting period (generally one to three years). The unamortized deferred compensation obligation amounted to $7.8 million as of December 31, 2008 and will be amortized to expense over the next three years. The table below summarizes restricted stock activity for
the three years ended December 31, 2008:
| |
|
|
|
|
Weighted- |
|
|
|
|
Shares/ |
|
|
Average |
|
|
|
|
Units |
|
|
Price |
|
|
Unvested restricted stock shares at December 31, 2005 |
|
|
87,585 |
|
|
$ |
15.98 |
|
|
Granted |
|
|
303,968 |
|
|
|
27.42 |
|
|
Vested |
|
|
(38,812 |
) |
|
|
17.35 |
|
|
Forfeited |
|
|
(26,532 |
) |
|
|
23.31 |
|
|
Unvested restricted stock shares at December 31, 2006 |
|
|
326,209 |
|
|
|
25.87 |
|
|
Granted |
|
|
132,719 |
|
|
|
40.26 |
|
|
Vested |
|
|
(86,199 |
) |
|
|
25.13 |
|
|
Forfeited |
|
|
(20,880 |
) |
|
|
31.21 |
|
|
Unvested restricted stock shares at December 31, 2007 |
|
|
351,849 |
|
|
|
31.15 |
|
|
Granted |
|
|
215,469 |
|
|
|
35.43 |
|
|
Vested |
|
|
(217,113 |
) |
|
|
28.65 |
|
|
Forfeited |
|
|
(8,507 |
) |
|
|
42.00 |
|
|
Unvested restricted stock shares at December 31, 2008 |
|
|
341,698 |
|
|
$ |
34.93 |
|
| |
|
|
|
|
|
|
|
|
9. RELATED-PARTY TRANSACTIONS
Marcellus Shale Joint Venture. Effective as of August 1, 2008, a wholly-owned subsidiary Carrizo (Marcellus) LLC entered into a joint venture arrangement with Avista, a private equity fund. Under the terms of the joint venture, the Company and Avista each committed
to contribute up to $150 million in cash and properties to acquire and develop acreage within an area of mutual interest located in the Marcellus Shale play, including the dedication of all of their respective Marcellus leasehold owned at the time of the formation of the joint venture.
The Company serves as operator of the joint venture with Avista under a joint operating agreement with Avista and provides all geotechnical, land, engineering and accounting support to the joint venture. The Company has also agreed to perform specified management services for the Avista affiliate that is the Company’s partner in
the joint venture on the same cost and reimbursement bases provided for in the joint operating agreement. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. Each representative has a vote equal to the participating interest in the properties and operations of the party it represents. Avista or its designee has the right to become a co-operator of the properties if all of its membership interests or substantially all of its assets
are sold to an unaffiliated third party or if the Company defaults under the terms of any pledge of its interest in the properties.
Under the terms of the joint venture, each party committed to contribute up to $150 million in cash and properties to acquire and develop acreage in the Marcellus Shale play, including the dedication of all of its Marcellus Shale leasehold owned at the time of the formation of the joint. In connection with formation of the joint venture,
Avista contributed certain leasehold interests (costing approximately $27.5 million) and agreed to fund 100% of the joint venture’s next approximately $71.5 million of expenditures related to the Marcellus Shale play (the “Initial Cash Contribution”). After the Initial Cash Contribution has been funded by Avista, the parties will share all costs of joint venture operations in accordance with their participating interests, which the Company expects will generally be 50/50. As a result of Avista’s
obligation to fund the Initial Cash Contribution, the Company does not currently expect that it will be required to contribute any cash to fund capital and exploration expenditures in the Marcellus Shale during 2009.
Subject to specified exceptions, net cash flow from hydrocarbon production from the Marcellus joint venture properties and related sales proceeds, if the properties are sold, will be allocated first to the joint venture partners in proportion to their respective investments (with property dedications generally valued on a cost basis) until
Avista has recovered its investment, then 100% to the Company until it recovers approximately $33.5 million, and thereafter in accordance with the parties’ participating interests, which the Company expects will generally be 50/50. The Company has also agreed to jointly market Avista’s share of the production from the properties with its own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under the joint operating agreement. In addition
to the Company’s share in the production and sale proceeds from joint venture properties, the Company also acquired as part of the transaction (through a wholly-owned subsidiary) an interest in the Avista joint venture entity that entitles the Company to increasing percentages of the Avista entity’s profits if that entity’s members receive a return of their investment and specified internal rates of return on these investments are achieved.
The
Company’s interest in the Avista entity provides consent rights only in limited, specified circumstances and generally does not entitle the Company to vote or participate in the management of the Avista entity, which is controlled by its members and affiliates.
As part of the transaction, and subject to certain exceptions, the parties agreed to enter into an area of mutual interest covering the Marcellus Shale play, wherein any lease, royalty or mineral rights acquired by one party within the area must be proportionately offered to the other on the same terms and conditions. The area of mutual
interest will remain in place until the earliest to occur of the following events, at which time the area of mutual interest will only continue to apply to those areas where the joint venture is active: (1) December 31, 2010, (2) the date on which the parties’ collective investment reaches $300 million, (3) upon Avista’s request to be designated (or have its designee designated) as a co-operator of the properties in connection with the sale to an unaffiliated third party of all of its membership interests
or substantially all of its assets and (4) upon the required designation of Avista (or its designee) as a co-operator of the properties in connection with the Company’s default under the terms of any pledge of the Company’s interest in the properties.
The parties have limited rights to transfer their respective interests in the properties until the Initial Cash Contribution has been satisfied. After that time, each party’s ability to transfer its interest in the joint venture to third parties is subject in most instances to preferential purchase rights for transfers of less than
10% of its interest in joint venture properties, or to “tag along” rights for most other transfers. Avista’s tag along rights do not apply upon a change of control of Carrizo.
Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which has the ability to control Avista. As previously disclosed, the Company has been a party to prior arrangements with affiliates of Avista Capital Holdings, LP in respect of the Company’s
investment in Pinnacle Gas Resources, Inc.
Avista Land Bank Agreement. In order to expand the Company’s lease acquisition efforts in the Marcellus Shale play, the
Company elected to enter into a lease option agreement effective August 1, 2008 with Avista, the Company’s partner in the Marcellus Shale play. See “Business and Properties—Significant Project Areas; Marcellus Shale Area.” The terms and conditions of the lease purchase option arrangement with Avista were generally
consistent with lease option arrangements that the Company has traditionally entered into with other third parties. Avista paid approximately $27.5 million for the oil and gas leases under the lease purchase option agreement and subsequently contributed these properties at their cost to the Company’s Marcellus joint venture, effective August 1, 2008.
Other Transactions. The Company’s Chairman of the Board, Mr. Steven A. Webster serves on the Board of Directors for Basic Energy Services, Inc., Grey Wolf Inc., Hercules Offshore L.L.C., Pinnacle Gas Resources, Inc. and Geokinetics, Inc., the parent of Quantum
Geophysical, Inc., and previously served on the Board of Directors of each of Goodrich Petroleum and Brigham Exploration. The Company’s Chief Executive Officer, Mr. S.P. Johnson serves as member on the Board of Directors of Basic Energy Services, Inc. and Pinnacle Gas Resources, Inc. Mr. Thomas L. Carter, Jr., a member of the Company’s Board of Directors, is the Chief Executive Officer and owner of a significant interest in Black Stone Minerals Company, L.P. (“Black Stone Minerals”). Mr.
F. Gardner Parker serves on the Board of Directors for Hercules Offshore, L.L.C. Due to these relationships, the Company has deemed these companies to be related parties. The Company incurred the following costs with these related parties:
| |
|
Year Ended December 31, |
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
(In millions) |
|
|
|
Basic Energy Services |
|
$ |
0.4 |
|
|
$ |
0.2 |
|
|
$ |
0.5 |
|
|
|
Grey Wolf Drilling |
|
|
7.1 |
|
|
|
6.8 |
|
|
|
6.7 |
|
|
|
Brigham Exploration(1) |
|
|
- |
|
|
|
(0.3 |
) |
|
|
(0.6 |
) |
(2) |
|
Quantum Geophysical Inc. |
|
|
- |
|
|
|
- |
|
|
|
0.2 |
|
|
|
Hercules Offshore, L.L.C. |
|
|
3.2 |
|
|
|
- |
|
|
|
- |
|
|
____________
|
(1) |
At the end of the first quarter of 2007, Mr. Webster resigned from the Board of Directors of Goodrich Petroleum and Brigham Exploration. As such, these companies are no longer deemed related parties after the first quarter of 2007. |
|
(2) |
Includes $1.2 million of net revenues related to wells operated by Brigham Exploration and $0.6 million of net revenues related to wells operated by the Company. |
It is management’s opinion that the transactions with these entities were executed at prevailing market rates. At December 31, 2008 and 2007, the Company had an outstanding related-party net receivable balance of approximately $66,000 and net payable balance of approximately $22,000, respectively.
In January 2006, the Company acquired certain oil and gas leases for approximately $1.1 million from Black Stone Acquisitions Partners I L.P., the general partner of which is Black Stone Minerals. Black Stone Acquisition Partners also retains
a royalty interest in the acquired leases, which are located in Mississippi. During 2007, the Company acquired additional acreage located in Texas from Black Stone for approximately $0.2 million. During 2008, the Company did not acquire any additional acreage from Black Stone. The terms and conditions of the lease agreement with Black
Stone Acquisitions Partners I L.P. and Black Stone are generally consistent with the lease agreements that the Company has entered into with other third parties. Additionally, the Company operates four producing wells in which affiliates of Black Stone Minerals hold a royalty interest for which the Company paid approximately $0.6 and $0.8 million in 2008 and 2007, respectively.
Due to the limited capital available at times to fund all of the Company’s ongoing lease acquisition efforts in the Barnett Shale, Marcellus Shale, Fayetteville Shale and other plays, the Company elects from time to time to enter into various lease purchase option agreements with a number of third parties, including, in 2006, Steven
A. Webster, the Company’s Chairman of the Board. The lease purchase option arrangement with Mr. Webster expired at the end of 2006. The terms and conditions of the lease purchase option arrangement with Mr. Webster were consistent with the lease purchase option arrangements the Company entered into with unrelated third parties. These lease purchase option arrangements provide the Company the option to purchase leases from the counterparties, over an option period, generally 90 days, for the counterparties’
original cost of the leases plus an option fee. The Company paid Mr. Webster fees totaling approximately $250,000 in 2006. In accordance with the lease purchase option agreement, the Company also assigned to Mr. Webster an overriding royalty interest on any lease the Company acquired from Mr. Webster under the lease purchase option agreement with him, which overriding royalty interest varied from one-half to one percent of 8/8ths, proportionally reduced to the actual net interest in any given lease acquired from
Mr. Webster. We paid Mr. Webster approximately $430 and $50 in 2008 and 2007, respectively, in overriding royalties under these arrangements.
See Note 3 for a discussion of the investment in Pinnacle.
Mr. Webster is also Co-Managing Partner and President of Avista Capital Holdings, L.P. and is therefore a related party to the Pinnacle transaction.
10. DERIVATIVE FINANCIAL INSTRUMENTS
The Company enters into swaps, options, collars and other derivative contracts to manage price risks associated with a portion of anticipated future oil and natural gas production. While the use of derivative financial instruments limits the downside risk of adverse price movements, it may also limit future gains from favorable movements.
Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company enters into the majority of its derivative transactions with two counterparties and netting agreements are in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and
believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the financial instruments. The Company used interest rate swap agreements to manage the Company’s exposure to interest rate fluctuations on borrowings under the Second
Lien Credit Facility, which was terminated during 2008.
The Company accounts for its oil and natural gas derivatives and interest rate swap agreements as non-designated hedges. These derivatives are marked-to-market at each balance sheet date and the unrealized gains (losses) are reported in the net gain (loss) on derivatives in Other Income and Expenses in the Consolidated Statement of Operations.
In addition, the Company records the realized gains (losses) associated with the cash settlements of these derivative instruments in the net gain (loss) on derivatives in Other Income and Expenses in the Consolidated Statement of Operations. For the years ended December 31, 2008, 2007 and 2006, the Company recorded the following related to its derivatives:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In millions) |
|
|
Realized gain (loss) |
|
|
|
|
|
|
|
|
|
|
Natural gas and oil derivatives |
|
$ |
0.6 |
|
|
$ |
5.8 |
|
|
$ |
6.8 |
|
|
Interest rate swaps |
|
|
(1.2 |
) |
|
|
0.2 |
|
|
|
1.0 |
|
|
Gain (loss) on interest rate swap sell down |
|
|
(3.3 |
) |
|
|
- |
|
|
|
0.6 |
|
| |
|
|
(3.9 |
) |
|
|
6.0 |
|
|
|
8.4 |
|
|
Unrealized gain (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil derivatives |
|
|
38.6 |
|
|
|
(4.6 |
) |
|
|
8.7 |
|
|
Interest rate swaps |
|
|
2.8 |
|
|
|
(2.8 |
) |
|
|
(0.6 |
) |
| |
|
|
41.4 |
|
|
|
(7.4 |
) |
|
|
8.1 |
|
|
Net Gain (Loss) on Derivatives |
|
$ |
37.5 |
|
|
$ |
(1.4 |
) |
|
$ |
16.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 the Company had the following outstanding derivative positions:
| |
|
Natural Gas Swaps |
|
|
Natural Gas Collars |
|
|
Basis Differential Swaps(2) |
|
| |
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed |
|
|
|
|
|
Floor |
|
|
Ceiling |
|
|
|
|
|
|
|
|
Quarter |
|
Mmbtus |
|
|
Price(1) |
|
|
MMBtus |
|
|
Price(1) |
|
|
Price(1) |
|
|
MMBtus |
|
|
Price |
|
|
First Quarter 2009 |
|
|
2,803,000 |
|
|
$ |
6.13 |
|
|
|
2,520,000 |
|
|
$ |
7.37 |
|
|
$ |
9.10 |
|
|
|
310,000 |
|
|
$ |
0.31 |
|
|
Second Quarter 2009 |
|
|
1,547,000 |
|
|
|
5.40 |
|
|
|
2,548,000 |
|
|
|
7.12 |
|
|
|
8.85 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2009 |
|
|
- |
|
|
|
- |
|
|
|
2,576,000 |
|
|
|
7.16 |
|
|
|
8.88 |
|
|
|
920,000 |
|
|
|
0.31 |
|
|
Fourth Quarter 2009 |
|
|
- |
|
|
|
- |
|
|
|
2,576,000 |
|
|
|
7.17 |
|
|
|
8.90 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,620,000 |
|
|
|
7.92 |
|
|
|
9.63 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,638,000 |
|
|
|
7.18 |
|
|
|
8.89 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,656,000 |
|
|
|
7.35 |
|
|
|
9.06 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2010 |
|
|
- |
|
|
|
- |
|
|
|
1,656,000 |
|
|
|
7.45 |
|
|
|
9.16 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
450,000 |
|
|
|
9.70 |
|
|
|
11.70 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
8.25 |
|
|
|
10.25 |
|
|
|
- |
|
|
|
- |
|
|
Third Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
460,000 |
|
|
|
8.65 |
|
|
|
10.65 |
|
|
|
- |
|
|
|
- |
|
|
Fourth Quarter 2011 |
|
|
- |
|
|
|
- |
|
|
|
460,000 |
|
|
|
8.85 |
|
|
|
10.85 |
|
|
|
- |
|
|
|
- |
|
|
First Quarter 2012 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
9.55 |
|
|
|
11.55 |
|
|
|
- |
|
|
|
- |
|
|
Second Quarter 2012 |
|
|
- |
|
|
|
- |
|
|
|
455,000 |
|
|
|
8.35 |
|
|
|
10.35 |
|
|
|
- |
|
|
|
- |
|
|
TOTAL |
|
|
4,350,000 |
|
|
|
|
|
|
|
19,525,000 |
|
|
|
|
|
|
|
|
|
|
|
1,230,000 |
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil Collars |
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
Quarter |
|
Bbls |
|
|
Floor Price(3) |
|
|
Ceiling Price(3) |
|
|
First Quarter 2009 |
|
|
9,000 |
|
|
$ |
131.65 |
|
|
$ |
151.65 |
|
|
Second Quarter 2009 |
|
|
9,100 |
|
|
|
131.40 |
|
|
|
151.40 |
|
|
Third Quarter 2009 |
|
|
9,200 |
|
|
|
130.85 |
|
|
|
150.85 |
|
|
Fourth Quarter 2009 |
|
|
9,200 |
|
|
|
130.35 |
|
|
|
150.35 |
|
|
TOTAL |
|
|
36,500 |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Based on Houston Ship Channel (HSC) and WAHA spot prices. |
|
(2) |
Basis differential swaps cover the price differential for natural gas between NYMEX and HSC. |
|
(3) |
Based on West Texas intermediate index prices. |
The fair value of the outstanding oil and natural gas derivatives at December 31, 2008 and 2007 was an asset of $38.7 million and $0.1 million, respectively.
At December 31, 2008, approximately 69% of the Company’s open natural gas hedges were with Credit Suisse, and the remaining 31% were with Shell Energy North America (US), L.P. The open oil hedge positions were all arranged with Credit Suisse.
During the third quarter of 2005, the Company entered into interest rate swap agreements with respect to amounts outstanding under the Second Lien Credit Facility. These arrangements were designed to manage the Company’s exposure to interest rate fluctuations during the period beginning January 1, 2006 through June 30, 2007 by effectively
exchanging existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBO rates. In connection with an amendment to the Second Lien Credit Facility, the remaining open derivative positions on interest rate swaps were cash settled, resulting in a realized gain of $0.6 million on December 21, 2006.
During the first and second quarter of 2007, the Company entered into interest swap agreements covering amounts outstanding under the Second Lien Credit Facility. These arrangements were designed to manage the Company’s exposure to interest rate fluctuations through December 31, 2008 by effectively exchanging existing obligations
to pay interest based on floating rates with obligations to pay interest based on fixed LIBOR. In connection with the Company’s repayment of borrowings under and termination of the Second Lien Credit Facility, following the issuance of the Convertible Senior Notes in May 2008, the remaining open derivative positions on interest rates were cash settled, resulting in a realized loss of $3.3 million on the remaining positions covering the period from May 28, 2008 to December 31, 2008.
11. FAIR VALUE MEASUREMENTS
Effective January 1, 2008, the Company adopted FASB Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs
used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS No. 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures.
The Company elected to implement SFAS No. 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157,” issued February 2008, which defers the effective
date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
SFAS No. 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:
| |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
|
(in thousands) |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Pinnacle Gas Resources, Inc. |
|
$ |
751 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
751 |
|
|
Oil and natural gas derivatives |
|
|
- |
|
|
|
38,667 |
|
|
|
- |
|
|
|
38,667 |
|
|
Total |
|
$ |
751 |
|
|
$ |
38,667 |
|
|
$ |
- |
|
|
$ |
39,418 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas derivatives are valued by a third-party consultant using valuation models that are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments,
as well as other relevant economic measures.
Effective January 1, 2008 the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115”
(“SFAS No. 159”). SFAS No. 159 allows companies to choose to measure financial instruments and other items at fair value that previously were not required to be measured at fair value. The Company elected not to present any financial instruments or other items at fair value that were not required to be presented at fair value prior to the adoption of SFAS No. 159.
|
12. |
SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) |
The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.”
Costs Incurred
Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
Property acquisition costs |
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
271,618 |
|
|
$ |
54,467 |
|
|
$ |
48,409 |
|
|
Proved |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Exploration costs |
|
|
235,382 |
|
|
|
144,402 |
|
|
|
104,473 |
|
|
Development costs |
|
|
49,626 |
|
|
|
30,562 |
|
|
|
37,889 |
|
|
Asset retirement obligation |
|
|
630 |
|
|
|
1,961 |
|
|
|
299 |
|
|
Total costs incurred(1) |
|
$ |
557,256 |
|
|
$ |
231,392 |
|
|
$ |
191,070 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Excludes capitalized interest on unproved properties of $20.5 million, $11.7 million and $10.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, and includes capitalized overhead of $7.8 million, $4.5 million and $3.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. |
Oil And Natural Gas Reserves
Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 2008, 2007 and 2006, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company Petroleum Engineers, LaRoche Petroleum Consultants, Ltd., and Fairchild & Wells, Inc. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission.
The Company’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:
| |
|
Millions of Cubic Feet |
|
|
|
|
of Natural Gas |
|
|
|
|
at December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Proved developed and undeveloped reserves — |
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
248,433 |
|
|
|
166,798 |
|
|
|
103,058 |
|
|
Purchase of oil and natural gas properties in place |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Discoveries and extensions |
|
|
146,189 |
|
|
|
131,836 |
|
|
|
91,090 |
|
|
Revisions |
|
|
21,661 |
|
|
|
(34,017 |
) |
|
|
(11,026 |
) |
|
Sales of oil and gas properties in place |
|
|
- |
|
|
|
(142 |
) |
|
|
(6,148 |
) |
|
Production |
|
|
(23,547 |
) |
|
|
(16,042 |
) |
|
|
(10,176 |
) |
|
End of year |
|
|
392,736 |
|
|
|
248,433 |
|
|
|
166,798 |
|
|
Proved developed reserves at beginning of year |
|
|
122,598 |
|
|
|
73,912 |
|
|
|
44,681 |
|
|
Proved developed reserves at end of year |
|
|
216,229 |
|
|
|
122,598 |
|
|
|
73,912 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Thousands of Barrels of |
|
|
|
|
Oil, Condensate and |
|
|
|
|
Natural Gas Liquids |
|
|
|
|
at December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
Proved developed and undeveloped reserves - |
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
16,531 |
|
|
|
7,195 |
|
|
|
7,925 |
|
|
Purchase of oil and natural gas properties in place |
|
|
- |
|
|
|
796 |
|
|
|
- |
|
|
Discoveries and extensions |
|
|
2,088 |
|
|
|
3,536 |
|
|
|
359 |
|
|
Revisions |
|
|
36 |
|
|
|
5,245 |
|
|
|
(823 |
) |
|
Sales of oil and gas properties in place |
|
|
- |
|
|
|
- |
|
|
|
(11 |
) |
|
Production |
|
|
(347 |
) |
|
|
(241 |
) |
|
|
(255 |
) |
|
End of year |
|
|
18,308 |
|
|
|
16,531 |
|
|
|
7,195 |
|
|
Proved developed reserves at beginning of year |
|
|
6,536 |
|
|
|
1,638 |
|
|
|
1,343 |
|
|
Proved developed reserves at end of year |
|
|
7,869 |
|
|
|
6,536 |
|
|
|
1,638 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
During 2008, 2007 and 2006, the Company reported considerable discoveries and extensions to the Company’s natural gas reserves primarily due to the Company’s drilling program in the Barnett Shale play. In 2007, the Company recorded significant oil discoveries and extensions due to drilling and development activity in the Barnett
Shale region and additional formation evaluation in the Camp Hill field. In 2008, the Company included a large natural gas revision primarily due to actual performance of wells in the Barnett Shale. In 2007, the Company reported a large natural gas revision largely attributable to the reclass of natural gas liquids, previously presented as natural gas equivalents, to the reserve category of oil and condensate. During 2007, the Company increased production of natural gas liquids as a result of an increase in processed
gas sales. In prior years, any natural gas liquid production was deemed immaterial. The Company reported significant downward revisions to its natural gas reserves in 2006 due to a decline in natural gas prices.
Standardized Measure
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves as of year-end is shown below:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
Future cash inflows |
|
$ |
2,501,460 |
|
|
$ |
2,663,281 |
|
|
$ |
1,356,118 |
|
|
Future oil and natural gas operating expenses |
|
|
868,027 |
|
|
|
618,479 |
|
|
|
350,076 |
|
|
Future development costs |
|
|
315,837 |
|
|
|
277,070 |
|
|
|
193,245 |
|
|
Future income tax expenses |
|
|
407,897 |
|
|
|
394,569 |
|
|
|
202,685 |
|
|
Future net cash flows |
|
|
909,699 |
|
|
|
1,373,163 |
|
|
|
610,112 |
|
|
Less 10% annual discount for estimating timing of cash flows |
|
|
468,445 |
|
|
|
710,793 |
|
|
|
311,401 |
|
|
Standard measure of discounted future net cash flows |
|
$ |
441,254 |
|
|
$ |
662,370 |
|
|
$ |
298,711 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Average prices used in computing year end 2008, 2007 and 2006 future cash flows were $29.61, $74.45 and $54.73 for oil, respectively, and $4.99, $5.99 and $5.77 for natural gas, respectively.
Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Change in Standardized Measure
Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below:
| |
|
Year Ended December 31, |
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
(In thousands) |
|
|
Changes due to current-year operations - |
|
|
|
|
|
|
|
|
|
|
Sales of oil and natural gas, net of oil and natural |
|
$ |
(171,944 |
) |
|
$ |
(101,127 |
) |
|
$ |
(72,077 |
) |
|
gas operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries |
|
|
228,037 |
|
|
|
340,503 |
|
|
|
139,657 |
|
|
Purchases of oil and gas properties |
|
|
- |
|
|
|
20,625 |
|
|
|
- |
|
|
Changes due to revisions in standardized variables |
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices and operating expenses |
|
|
(371,924 |
) |
|
|
142,126 |
|
|
|
(71,814 |
) |
|
Income taxes |
|
|
22,307 |
|
|
|
(89,158 |
) |
|
|
16,422 |
|
|
Future development costs, net |
|
|
11,052 |
|
|
|
57,126 |
|
|
|
64,166 |
|
|
Revision of quantities |
|
|
44,643 |
|
|
|
(7,614 |
) |
|
|
(43,362 |
) |
|
Sales of reserves in place |
|
|
- |
|
|
|
(351 |
) |
|
|
(15,518 |
) |
|
Accretion of discount |
|
|
83,931 |
|
|
|
38,718 |
|
|
|
40,423 |
|
|
Production rates, timing and other |
|
|
(67,218 |
) |
|
|
(37,189 |
) |
|
|
(58,527 |
) |
|
Net change |
|
|
(221,116 |
) |
|
|
363,659 |
|
|
|
(630 |
) |
|
Beginning of year |
|
|
662,370 |
|
|
|
298,711 |
|
|
|
299,341 |
|
|
End of year |
|
$ |
441,254 |
|
|
$ |
662,370 |
|
|
$ |
298,711 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pretax discounted basis, while the accretion
of discount is presented on a before tax basis.
13. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree to year-to-date basic and diluted earnings (loss) per share amounts as a result of each period’s computation being based on the weighted average number of common shares outstanding during the period.
|
2008 |
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
(In thousands, except per share amounts) |
|
|
Revenues |
|
$ |
53,560 |
|
|
$ |
67,388 |
|
|
$ |
58,527 |
|
|
$ |
37,202 |
|
|
Costs and expenses, net |
|
|
58,856 |
|
|
|
80,168 |
(1) |
|
|
(7,188 |
)(1) |
|
|
129,888 |
(2) |
|
Net income (loss) |
|
$ |
(5,296 |
) |
|
$ |
(12,780 |
) |
|
$ |
65,715 |
|
|
$ |
(92,686 |
) |
|
Basic net income (loss) per share |
|
$ |
(0.18 |
) |
|
$ |
(0.42 |
) |
|
$ |
2.14 |
|
|
$ |
(3.01 |
) |
|
Diluted net income (loss) per share |
|
$ |
(0.18 |
) |
|
$ |
(0.42 |
) |
|
$ |
2.11 |
|
|
$ |
(3.01 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
|
(In thousands, except per share amounts) |
|
|
Revenues |
|
$ |
22,612 |
|
|
$ |
32,891 |
|
|
$ |
30,305 |
|
|
$ |
39,981 |
|
|
Costs and expenses, net |
|
|
25,157 |
|
|
|
24,754 |
|
|
|
26,072 |
|
|
|
34,337 |
|
|
Net income (loss) |
|
$ |
(2,545 |
) |
|
$ |
8,137 |
|
|
$ |
4,233 |
|
|
$ |
5,644 |
|
|
Basic net income (loss) per share |
|
$ |
(0.10 |
) |
|
$ |
0.31 |
|
|
$ |
0.16 |
|
|
$ |
0.20 |
|
|
Diluted net income (loss) per share |
|
$ |
(0.10 |
) |
|
$ |
0.31 |
|
|
$ |
0.16 |
|
|
$ |
0.20 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1) |
Includes a before tax $48.2 million loss and $77.7 million gain associated with derivatives for the second and third quarter, respectively. |
|
(2) |
Includes a before tax $178.5 million impairment of oil and gas properties. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
CARRIZO OIL & GAS, INC. |
|
| |
|
|
|
|
|
By: |
/s/Paul F. Boling |
|
| |
|
Paul F. Boling |
|
| |
|
Chief Financial Officer, Vice President, |
|
| |
|
Secretary and Treasurer |
|
| |
|
|
|
| Date: August 17, 2009 |
|
|
|